Valaris Ltd - Annual Report: 2022 (Form 10-K)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 | ||
FORM 10-K
(Mark One)
| ☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2022
| OR | ||
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to | ||||
Commission File Number 1-8097
| Valaris Limited | ||
| (Exact name of registrant as specified in its charter) | ||
| Bermuda | 98-1589854 | |||||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||
| Clarendon House, 2 Church Street | ||||||||||||||
| Hamilton | Bermuda | HM 11 | ||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
Registrant's telephone number, including area code: +44 (0) 20 7659 4660
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of each class | Ticker Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common Shares, $0.01 par value share | VAL | New York Stock Exchange | ||||||||||||
| Warrants to purchase Common Shares | VAL WS | New York Stock Exchange | ||||||||||||
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act:
| Large accelerated filer | ☒ | Accelerated filer | o | |||||||||||
| Non-Accelerated filer | o | Smaller reporting company | ☐ | |||||||||||
| Emerging growth company | ☐ | |||||||||||||
☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☒ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes ☒ No ☐
The aggregate market value of the common shares (based upon the closing price on the New York Stock Exchange on June 30, 2022 of $42.24 of the registrant held by non-affiliates of Valaris Limited at that date) was approximately $2.8 billion.
As of February 16, 2023, there were 75,181,098 common shares of the registrant issued and outstanding.
| TABLE OF CONTENTS | |||||||||||
| PART I | ITEM 1. | ||||||||||
| ITEM 1A. | |||||||||||
| ITEM 1B. | |||||||||||
| ITEM 2. | |||||||||||
| ITEM 3. | |||||||||||
| ITEM 4. | |||||||||||
| PART II | ITEM 5. | ||||||||||
| ITEM 6 | |||||||||||
ITEM 7. | |||||||||||
ITEM 7A. | |||||||||||
| ITEM 8. | |||||||||||
| ITEM 9. | |||||||||||
| ITEM 9A. | |||||||||||
| ITEM 9B. | |||||||||||
| PART III | ITEM 10. | ||||||||||
| ITEM 11. | |||||||||||
| ITEM 12. | |||||||||||
| ITEM 13. | |||||||||||
| ITEM 14. | |||||||||||
| PART IV | ITEM 15. | ||||||||||
| ITEM 16. | |||||||||||
FORWARD-LOOKING STATEMENTS
Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "likely," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; expected utilization, day rates, revenues, operating expenses, cash flows, contract status, terms and duration, contract backlog, capital expenditures, insurance, financing and funding; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effect of the volatility of commodity prices; expected work commitments, awards, contracts and letters of intent; the availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; rig reactivations, enhancement, upgrade or repair and timing and cost thereof; the suitability of rigs for future contracts; performance of our joint ventures, including our joint venture with Saudi Arabian Oil Company ("Saudi Aramco"); divestitures of assets; general market, business and industry conditions, trends and outlook; general political conditions, including political tensions, conflicts and war (such as the ongoing conflict in Ukraine); the effect, impact, potential duration and other implications of COVID-19; future operations; the impact of increasing regulatory complexity; the outcome of tax disputes, assessments and settlements; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims or contract disputes and the timing thereof.
Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:
•delays in contract commencement dates or cancellation, suspension, renegotiation or termination with or without cause of drilling contracts or drilling programs as a result of general or industry-specific economic conditions, mechanical difficulties, performance, delays in the delivery of critical drilling equipment, failure of the customer to receive final investment decision (FID) for which the drilling rig was contracted or other reasons;
•changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs or reactivation of stacked drilling rigs;
•general economic and business conditions, including recessions, inflation, and adverse changes in the level of international trade activity;
•requirements to make significant expenditures in connection with rig reactivations, customer drilling requirements and to comply with governing laws or regulations in the regions we operate;
•loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, including focusing on renewable energy projects;
•our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, rising wages, unionization, or otherwise, or to retain employees;
•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems, including our rig operating systems;
•the adequacy of sources of liquidity for us and our customers;
•risks inherent to drilling rig reactivations, repair, modification or upgrades, unexpected delays in equipment delivery, engineering, design or commissioning issues following delivery, or changes in the commencement, completion or service dates;
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•our ability to generate operational efficiencies from our shared services center and potential risks relating to the processing of transactions and recording of financial information;
•downtime and other risks associated with offshore rig operations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris;
•our customers cancelling or shortening the duration of our drilling contracts, cancelling future drilling programs and seeking pricing and other contract concessions from us;
•decreases in levels of drilling activity and capital expenditures by our customers, whether as a result of the global capital markets and liquidity, prices of oil and natural gas, changes in tax policy (such as the U.K.’s recently announced windfall tax on oil and gas producers in the British North Sea), climate change concerns or otherwise, which may cause us to idle, stack or retire additional rigs;
•the COVID-19 pandemic, the related public health measures implemented by governments worldwide, the duration and severity of the outbreak and its impact on global oil demand, the volatility in prices for oil and natural gas and the extent of disruptions to our operations;
•downtime or temporary shutdown of operations of our rigs as a result of an outbreak of COVID-19 on one or more of our rigs;
•disruptions to the operations and business of our key customers, suppliers and other counterparties, including impacts affecting our supply chain and logistics;
•governmental action, terrorism, cyber-attacks, piracy, military action and political and economic uncertainties, including civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East, North Africa, West Africa, Southeast Asia, Eastern Europe or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation or destruction of our assets; suspension and/or termination of contracts based on force majeure events or adverse environmental safety events; or volatility in prices of oil and natural gas;
•disputes over production levels among members of the Organization of Petroleum Exporting Countries and other oil and gas producing nations (“OPEC+”), which could result in increased volatility in prices for oil and natural gas that could affect the markets for our services;
•our ability to enter into, and the terms of, future drilling contracts, including contracts for newbuild rigs or acquired rigs, for rigs currently idled and for rigs whose contracts are expiring;
•any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments;
•the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any renegotiation, nullification, cancellation or breach of contracts with customers or other parties;
•internal control risk due to significant employee reductions and changes in management and our shared service center;
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•governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations, limitations on new oil and gas leasing in U.S. federal lands and waters, and regulatory measures to limit or reduce greenhouse gas emissions;
•governmental policies that could reduce demand for hydrocarbons, including mandating or incentivizing the conversion from internal combustion engine powered vehicles to electric-powered vehicles;
•consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition;
•increased scrutiny from regulators, market and industry participants, stakeholders and others in regard to our environmental, social and governance ("ESG") practices and reporting responsibilities;
•potential impacts on our business resulting from climate-change or greenhouse gas legislation or regulations, and the impact on our business from climate-change related physical changes or changes in weather patterns;
•new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts, operations or financial results;
•environmental or other liabilities, risks, damages or losses, whether related to storms, hurricanes or other weather-related events (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions, cyberattacks, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;
•tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;
•our ability to realize the expected benefits of our joint venture with Saudi Aramco, including our ability to fund any required capital contributions or to enforce any payment obligations of the joint venture pursuant to outstanding shareholder notes receivable and benefits of our other joint ventures;
•the potentially dilutive impacts of warrants issued pursuant to the plan of reorganization;
•the costs, disruption and diversion of our management's attention associated with campaigns by activist securityholders; and
•adverse changes in foreign currency exchange rates.
In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.
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PART I
Item 1. Business
General
Valaris Limited is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Valaris," "Company," "we," "us" and "our" refer to Valaris Limited together with all its subsidiaries and predecessors.
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. We currently own 52 rigs, including 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 36 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional seven rigs. We also have options to purchase two recently constructed drillships on or before December 31, 2023.
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 current operations spanning six continents. The markets in which we operate include the Gulf of Mexico, South America, the North Sea, 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.
In 2020, the combined effects of the global COVID-19 pandemic, the significant decline in the demand for oil and the substantial surplus in the supply of oil resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions. These events had a significant adverse impact on our expected liquidity position and financial runway and led to the filing of the Chapter 11 Cases (as defined herein).
In 2021, Brent crude oil prices increased from approximately $50 per barrel at the beginning of the year to nearly $80 per barrel by the end of the year. Increased oil prices were due to, among other factors, rebounding demand for hydrocarbons, a measured approach to production increases by OPEC+ members and a focus on cash flow and returns by major exploration and production companies. The constructive oil price environment led to an improvement in contracting and tendering activity in 2021 as compared to 2020.
Oil prices remained volatile through 2022. In the first half of 2022, Brent crude oil prices and volatility increased dramatically, in large part due to Russia’s invasion of Ukraine, which led to sanctions being placed on Russia, including its ability to export crude oil and other petroleum products. The anticipated impact on supply drove Brent crude oil prices above $130 per barrel in early March 2022. By the end of December 2022, the Brent crude price had declined to approximately $83 per barrel due in part to high inflation rates and fears of a global recession that could negatively impact oil demand.
Despite the high volatility in spot oil prices described above, our customers tend to be more focused on medium-term and long-term commodity prices when making investment decisions due to the longer lead times for offshore projects. These forward prices experienced far less volatility in 2022 and have maintained levels which are highly constructive for offshore project demand.
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The outlook for the offshore drilling industry has improved since the beginning of 2021, as evidenced by increasing global utilization and day rates for offshore drilling rigs, most notably for drillships. However, heightened geopolitical tensions have increased volatility, inflation is increasing costs of operations and the impacts from the COVID-19 pandemic remains uncertain. More recently, the combination of global inflation and a tightening of monetary policy has led to increasing fears of a global economic recession that may have a negative impact on demand for hydrocarbons. As a result, there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for, and profitability of, offshore drilling services.
Chapter 11 Proceedings and Emergence from Chapter 11
On August 19, 2020 (the “Petition Date”), Valaris plc (“Legacy Valaris” or “Predecessor”) and certain of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”). On March 3, 2021, the Bankruptcy Court confirmed the Debtors' chapter 11 plan of reorganization.
In connection with the Chapter 11 Cases, on and prior to April 30, 2021 (the "Effective Date"), Legacy Valaris effectuated certain restructuring transactions, pursuant to which the successor company, Valaris, was formed and through a series of transactions Legacy Valaris transferred to a subsidiary of Valaris substantially all of the subsidiaries, and other assets, of Legacy Valaris.
On the Effective Date, we successfully completed our financial restructuring and together with the Debtors emerged from the Chapter 11 Cases. Upon emergence from the Chapter 11 Cases, we eliminated $7.1 billion of debt and obtained a $520 million capital injection by issuing the first lien secured notes (the "First Lien Notes"). See “Note 8 - Debt" for additional information on the First Lien Notes. On the Effective Date, the Legacy Valaris Class A ordinary shares were cancelled and common shares of Valaris with a nominal value of $0.01 per share (the “Common Shares”) were issued. Also, former holders of Legacy Valaris' equity were issued warrants (the "Warrants") to purchase Common Shares.
See “Note 2 – Chapter 11 Proceedings” and "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional details regarding the reorganization, Chapter 11 Cases and related items.
Contract Drilling Operations
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 lease arrangements with ARO. Floaters, Jackups and ARO are also reportable segments.
We own and operate 52 rigs, of which 17 are located in the Middle East and Africa, 16 are located in Europe and the Mediterranean, 13 are located in North and South America and six are located in Asia and Pacific Rim as of December 31, 2022.
Our drilling rigs drill and complete oil and natural gas wells. From time to time, our drilling rigs may be utilized as accommodation units or for non-drilling services, such as workovers and interventions, plug and abandonment and decommissioning work. Demand for our drilling services is based upon many factors beyond our control. See “Item 1A. Risk Factors - The success of our business depends on the level of activity in offshore oil and natural gas exploration, which can be significantly affected by volatile oil and natural gas prices.”
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Our drilling contracts are negotiated with our customers, and most contracts are awarded following competitive bidding. The terms of our drilling contracts vary, but generally contain the following commercial terms:
•contract duration or term for a specific period of time or a period necessary to drill one or more wells,
•term extension options, exercisable by our customers, upon advance notice to us, at mutually agreed, indexed, fixed rates or current rate at the date of extension,
•provisions permitting early termination of the contract, which may include (1) if the rig is lost or destroyed, (2) if operations are suspended for a specified period of time due to various events, including damage or breakdown of major rig equipment, unsatisfactory performance, or "force majeure" events, (3) failure of the customer to receive final investment decision (FID) approval with respect to projects for which the drilling rig was contracted or (4) at the convenience (without cause) of the customer, exercisable upon advance notice to us, and in certain cases without making an early termination payment to us,
•payment of compensation to us is (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a day rate basis such that we receive a fixed amount for each day that the drilling rig is under contract (lower day rates generally apply for periods when operations are suspended due to various events, including during delays that are beyond our reasonable control, during repair of equipment damage or breakdown and during periods of re-drilling damaged portions of the well, and no day rate, or zero rate, generally applies when these limited periods are exceeded until the event is remediated, and during periods to remediate unsatisfactory performance or other specified conditions),
•payment by us of the operating expenses of the drilling rig, including crew labor and incidental rig supply and maintenance costs,
•mobilization and demobilization requirements of us to move the drilling rig to and from the planned drilling site, and may include reimbursement of all or a portion of these moving costs by the customer in the form of an up-front payment, additional day rate over the contract term or direct reimbursement, and
•provisions allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment or direct reimbursement for certain cost increases due to changes in applicable law or rising operational expenses.
While contracting and tendering activity has increased, contract awards remain subject to a highly competitive bidding process, which could result in lower margin contracts that also contain less favorable contractual and commercial terms, including reduced or no mobilization and/or demobilization fees; reduced day rates or zero day rates during downtime; reduced standby, redrill and moving rates and reduced periods in which such rates are payable; reduced caps on reimbursements for lost or damaged downhole tools; reduced periods to remediate downtime due to equipment breakdowns or failure to perform in accordance with the contractual standards of performance before the operator may terminate the contract; certain limitations on our ability to be indemnified from operator and third- party damages caused by our fault, resulting in increases in the nature and amounts of liability allocated to us; and reduced or no early termination fees and/or termination notice periods.
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Backlog Information
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for backlog information.
Insurance and Indemnification Matters
Our insurance program provides coverage, subject to the policies' terms and conditions and to the extent not otherwise assumed by the customer under the indemnification provisions of the drilling contract, for third-party liability claims arising from our operations. Our insurance program provides coverage that is customary for our industry. Generally, our insurance program provides third-party liability coverage up to $750.0 million. We retain the risk for liability not indemnified by the customer in excess of, and for risks not covered by, our insurance coverage.
Well-control events generally include an unintended release from a well that cannot be contained by using equipment on site, such as a blowout preventer, by increasing the weight of drilling fluid or by diverting the fluids safely into production facilities. Our customers typically indemnify us for most well-control events.
Our insurance program also provides hull and machinery coverage to us for physical damage (including total loss) to our rigs, cargo and equipment, excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. We separately purchase a small limit of named windstorm insurance for our floater rigs in the U.S. Gulf of Mexico. We do not currently carry insurance for loss of hire. Any such lack of reimbursement from the loss of day rate revenues may cause us to incur substantial costs.
Our drilling contracts customarily provide that each party is responsible for injuries or death to their respective personnel and loss or damage to their respective property (including the personnel and property of each parties’ contractors and subcontractors) regardless of the cause of the loss or damage. However, in certain drilling contracts our customer’s responsibility for damage to its property and the property of its other contractors contains an exception to the extent the loss or damage is due to our negligence, which exception is usually subject to negotiated caps on a per occurrence basis, although in some cases we assume responsibility for all damages due to our negligence. In addition, our drilling contracts typically provide for our customers to indemnify us, generally based on replacement cost minus some level of depreciation, for loss or damage to our down-hole equipment, and in some cases for a limited amount of the repair of or replacement cost of our subsea equipment, unless the damage is caused by our negligence, normal wear and tear or defects in our equipment. We also maintain insurance for exposures to personal injuries, damage to or loss of property and certain business risks.
Subject to the exceptions noted below, our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination arising from operations, including as a result of blowouts, cratering and seepage, when the source of the pollution originates from the well or reservoir, including costs for clean-up and removal of pollution and third-party damages. In most drilling contracts, we assume liability for third-party damages resulting from such pollution and contamination caused by our negligence, usually subject to negotiated caps on a per occurrence or per event basis. In addition, in substantially all of our contracts, the customer assumes responsibility and indemnifies us for loss or damage to the reservoir, for loss of hydrocarbons escaping from the reservoir and for the costs of bringing the well under control. Further, subject to the exceptions noted below, most of our contracts provide that the customer assumes responsibility and indemnifies us for loss or damage to the well, except when the loss or damage to the well is due to our negligence, in which case most of our contracts provide that the customer's sole remedy is to require us to redrill the lost or damaged portion of the well at a substantially reduced rate and, in some cases, pay for some of the costs to repair the well.
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Most of our drilling contracts incorporate a broad exclusion that limits the operator's indemnity for damages and losses resulting from our gross negligence and willful misconduct and for fines and penalties and punitive damages levied or assessed directly against us. In most of these cases, we are still able to negotiate a liability cap (although these caps are significantly higher than the caps we are able to negotiate for ordinary negligence) on our exposure for losses or damages resulting from our gross negligence. In certain cases, the broad exclusion only applies to losses or damages resulting from the gross negligence of our senior supervisory personnel. However, in some cases we have contractually assumed significantly increased exposure or unlimited exposure for losses and damages due to the gross negligence of some or all our personnel, and in most cases, we are not able to contractually limit our exposure for our willful misconduct.
Notwithstanding our negotiation of express limitations in our drilling contracts for losses or damages resulting from our ordinary negligence and any express limitations (albeit usually much higher) for losses or damages in the event of our gross negligence, under the applicable laws that govern certain of our drilling contracts, the courts will not enforce any indemnity for losses and damages that result from our gross negligence or willful misconduct. As a result, under the laws of such jurisdictions, the indemnification provisions of our drilling contracts that would otherwise limit our liability in the event of our gross negligence or willful misconduct are deemed to be unenforceable as being contrary to public policy. Accordingly, in such jurisdictions we are exposed to unlimited liability for losses and damages that result from our gross negligence or willful misconduct, regardless of any express limitation of our liability in the relevant drilling contracts. Under the laws of certain jurisdictions, an indemnity from an operator for losses or damages of third-parties resulting from our gross negligence is enforceable, but an indemnity for losses or damages of the operator is not enforceable. In such cases, the contractual indemnity obligation of the operator to us would be enforceable with respect to third-party claims for losses of damages, such as may arise in pollution claims, but the contractual indemnity obligation of the operator to us with respect to injury or death to the operator's personnel and the operator’s damages to the well, to the reservoir and for the costs of well control would not be enforceable. Furthermore, although there is a lack of precedential authority for these types of claims in countries where the civil law is applied, in those situations where a fault based codified civil law system is applicable to our drilling contracts, as opposed to the common law system, the courts generally will not enforce a contractual indemnity clause that totally indemnifies us from losses or damages due to our gross negligence but may enforce the contractual indemnity over and above a cap on our liability for gross negligence, assuming the cap requires us to accept a significant amount of liability.
Similar to gross negligence, regardless of any express limitations in a drilling contract regarding our liability for fines and penalties and punitive damages, the laws of most jurisdictions will not enforce an indemnity that indemnifies a party for a fine or penalty that is levied or punitive damages arising from willful misconduct that are assessed directly against such party on the ground that it is against public policy to indemnify a party from a fine, loss, penalty or punitive damages, especially where the purpose of such levy or assessment is to deter the behavior that resulted in the fine, loss or penalty or punish such party for the behavior that warranted the assessment of punitive damages.
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract based on market conditions and customer requirements existing when the contract was negotiated and the interpretation and enforcement of applicable law when the claim is adjudicated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor a contractual indemnity obligation that is enforceable under applicable law. Our insurance program and the terms of our drilling contracts may change in the future.
In certain cases, vendors who provide equipment or services to us limit their pollution liability to a specific monetary cap, and we assume the liability above that cap. Typically, in the case of original equipment manufacturers, the cap is a negotiated amount based on mutual agreement of the parties considering the risk profiles and thresholds of each party. However, for smaller vendors, the liability is usually limited to the value, or double the value, of the contract for the purchase of such equipment or services.
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We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids, the discharge of which originates from our rigs or equipment above the surface of the water and in some cases from our subsea equipment. Our contracts generally provide that, in the event of any such spill from our rigs, we are responsible for fines and penalties.
Major Customers
We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During the year ended December 31, 2022, our five largest customers accounted for 43% of consolidated revenues. BP plc, our only customer who accounts for 10% or more of consolidated revenues, accounted for 15% of consolidated revenues.
Competition
The offshore contract drilling industry is highly competitive. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise also are factors.
Human Capital
We believe our people are one of the most important elements of our success, and we benefit from a motivated, engaged, and diverse workforce. Our approach to attracting, developing, and retaining a diverse workforce of high-performing talent is anchored in a long-term employment model that seeks to foster personal growth and engagement.
Purpose and Culture
At Valaris, our purpose is to provide responsible solutions that deliver energy to the world. Our values are designed to guide us in support of our purpose:
•Integrity – Doing the right thing; whether or not anyone is watching;
•Safety – Causing no harm is always a priority;
•Excellence – Delivering value to our customers while consistently raising the bar on performance;
•Respect – Treating others the way we would like to be treated;
•Ingenuity – Solving problems creatively; and
•Stewardship – Safeguarding where we work for the next generation
Our Ethics and Compliance Policy and our Code of Conduct (the “Code”) form the foundation of our compliance and ethics program, which provides guidance on how to uphold our values. We have translated the Code into nine different languages, making it widely accessible to our employees across the globe. We maintain an Ethics Hotline that is available to all employees, either online or by phone, to confidentially seek guidance or raise a concern.
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The Code is reviewed on a periodic basis and approved by our board of directors. To further support our values of respect and integrity, we have policies prohibiting corruption, bribery (including facilitation payments), money laundering, retaliation, and reprisals for raising concerns, including those related to worker rights, working conditions, mistreatment, fraud, and misconduct. In addition, we have adopted a policy against modern slavery and human trafficking in our business and our supply chains.
Employees
We employed approximately 5,450 personnel worldwide including contract employees, and approximately 3,933 personnel excluding contract employees, as of December 31, 2022. Our employees represented 71 nationalities spread across 26 locations. The majority of our personnel work on our offshore installations and are compensated on an hourly basis. A portion of our employees and contractors working outside of the U.S. are represented by collective bargaining or similar agreements, which are subject to periodic salary negotiation. As of December 31, 2022, women comprised 29% of our onshore employees and 1% of our offshore employees.
Employee Wellbeing and Engagement
We believe that one of the best ways to serve our customers is through creating a healthy, safe and engaging working and learning environment, where our employees are confident and comfortable to put their best work forward. We seek to promote a healthy environment by prioritizing the mental and physical health and needs of our employees while recognizing them for their achievements and accomplishments. For example, in most countries where we work, we offer an employee assistance program (“EAP”) to employees and their families. Our EAP provides access to counselors and other mental health professionals as well as discounts to fitness centers, financial guidance and other benefits in support of our overall commitment to maintain a healthy workforce.
Feedback from our employees plays a key role in creating an agile, collaborative and trustworthy culture. We use surveys to measure employee engagement as well as our ability to align and execute around a common vision and foster innovation and creativity. These surveys help our leaders analyze the impact of company practices and culture on performance and have created a roadmap for improvement.
Training and Competency
We are focused on developing talent and leadership among both our onshore and offshore employees. In 2021, we launched the Building Organizational Leadership (BOLD) training program. This program is designed to engage, support and provide leadership tools for our offshore supervisors, helping them assess and develop their team’s understanding and use of our safety processes and policies. Approximately 650 personnel attended the program in 2022.
In addition to the BOLD offshore program, we designed and piloted an onshore leadership program in 2022 which we expect to implement for our senior onshore leaders commencing in 2023.
We provide regular training in health, safety, environmental and emergency response to our employees, as relevant to their roles, and we mandate that our employees complete training related to the Code, covering topics such as anti-corruption, workplace behavior and conflicts of interest. In addition, in 2022, all employees were assigned human trafficking prevention training, including procedures for reporting concerns. Certain employees must also complete training on topics ranging from trade compliance to antitrust matters.
Safety
Our policies set the expectation that causing no harm is a priority while conducting our operations. We seek to control major operational hazards with effective safeguards and to implement our management systems to protect the health and safety of our personnel.
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Our Safe Systems of Work are designed with the aim of completing each job safely and efficiently:
•Work Instruction – Step-by-step description of how to complete specific work activities, including mandatory precautions to be implemented;
•Permit to Work – Formal authorization and control process for the safe execution of potentially hazardous work that may present risk to people, environment or assets;
•Energy Isolation – Formal isolation of all energy sources before performing work on equipment;
•Job Safety Analysis – Identification and control of job hazards before starting work; and
•Stop Work Authority – Empowerment to stop work if a risk to people, environment or assets is perceived to exist.
Sustainability
Consistent with our purpose of providing responsible solutions that deliver energy to the world, we have increased our focus on sustainability-related matters. Our board of directors' ESG Committee, formed in 2021, regularly meets to address sustainability topics and is responsible for overseeing the Company’s policies, programs and practices related to ESG responsibilities and the Company’s management of risks in such areas. In 2022, we created a new business function and management position focused on sustainability and new energy opportunities and have an employee-led cross-functional working group to identify and evaluate opportunities and promote sustainable business practices.
We publish an annual sustainability report aligned with Sustainability Accounting Standards Board (SASB) standards and report scope 1, 2 and 3 greenhouse gas (GHG) emissions. We also utilize technology that enables us to monitor fuel consumption and GHG emissions across our rig fleet. For further discussion of ESG risks and considerations see “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K.
We encourage you to review our latest Sustainability Report, located on our website (www.valaris.com), for more detailed information regarding our sustainability and human capital programs and initiatives. Nothing on our website, including our Sustainability Report or sections thereof, shall be deemed incorporated by reference into this report or other filings that we make with the SEC.
Governmental Regulation and Environmental Matters
Our operations are affected by laws, regulations and political initiatives that relate to the oil and natural gas industry, including laws and regulations that have or may impose increased oil-spill related and financial responsibility requirements. Laws and regulations curtailing exploration and development drilling for oil and natural gas will directly affect us for economic, environmental, safety or other policy reasons. It is also possible that these laws, regulations and political initiatives could adversely affect our operations in the future by significantly increasing our operating costs or restricting areas open for drilling activity. See "Item 1A. Risk Factors - Increasing regulatory complexity could adversely impact our offshore drilling operations and reduce demand."
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Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. These laws and regulations may, among other things:
•require the acquisition of various permits before drilling commences;
•require notice to stakeholders of proposed and ongoing operations;
•require the installation of expensive pollution control equipment;
•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling; and
•restrict the production rate of oil and natural gas below the rate that would otherwise be possible.
Failure to comply with environmental laws and regulations applicable to our operations could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations, which may not be indemnifiable or covered by insurance and could have a material adverse effect on our financial position, operating results and cash flows. To date, such laws and regulations have not had a material adverse effect on our operating results. However, the legislative, judicial and regulatory response to any environmental incident could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact our operating results.
Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation of existing laws/regulations, that result in more stringent and costly waste handling, disposal and cleanup requirements for our industry could have a significant impact on our operating costs.
The International Convention on Oil Pollution Preparedness, Response and Cooperation, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, the Oil Pollution Act of 1990 ("OPA 90"), as amended, the Clean Water Act and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention, reporting and control and have significantly expanded potential liability, fine and penalty exposure across many segments of the oil and natural gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation. Failure to comply with these statutes and regulations may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance, or for which indemnity is prohibited under applicable law, and could have a material adverse effect on our financial position, operating results and cash flows.
High-profile and catastrophic events such as the 2010 Macondo well incident have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the adoption of additional safety requirements and policies regarding the approval of drilling permits and restrictions on development and production activities in the U.S. Gulf of Mexico that have and may further impact our operations.
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On July 28, 2016, the Bureau of Safety and Environmental Enforcement ("BSEE") adopted the 2016 Well Control Rule. This rule included more stringent design requirements for well-control equipment used in offshore drilling operations. Subsequently, on May 2, 2019, BSEE issued the 2019 Well Control Rule, the revised well control and blowout preventer rule governing the Outer Continental Shelf (OCS) activities. The rule revised existing regulations impacting offshore oil and gas drilling, completions, workovers and decommissioning activities. We have not incurred significant costs to comply with the 2016 Well Control Rule or 2019 Well Control Rule.
The continuing and evolving threat of cyber attacks will likely require increased expenditures to strengthen cyber risk management systems for drilling rigs and onshore facilities. For example, on May 11, 2017, an executive order was issued entitled Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure, which is intended to improve the nation's ability to defend against increasing and evolving cyber attacks, and in March 2020 the United States Coast Guard issued cybersecurity guidelines for port facilities and offshore facilities, including drilling rigs, that could be impacted by cyber attacks. We cannot currently estimate the future expenditures associated with increased regulatory requirements, which may be material, and we continue to monitor regulatory changes as they occur.
Additionally, climate change is receiving increasing attention from scientists and legislators, and significant focus is being put on companies that are active producers of hydrocarbon resources. Globally, there are a number of legislative and regulatory proposals at various levels of government to address the greenhouse gas emissions that contribute to climate change, such as laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy and programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could require us or our customers to incur increased operating costs or incremental capital expenditures. Any such legislation or regulatory programs could also increase the cost of consuming oil and natural gas, and thereby reduce demand for oil and natural gas, which could reduce our customers’ demand for our services. Consequently, legislation and regulatory programs to reduce greenhouse gas emissions could have an adverse effect on our financial position, operating results and cash flows.
The United States reentered the Paris Agreement in February 2021. Further, in November 2021, the United States 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. It is expected that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, will be proposed and/or promulgated. For example, multiple executive orders pertaining to environmental regulations and climate change have recently been issued, including the (1) Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis ("EO 13990") and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad ("EO 14008"). EO 13990 established an interagency working group to recommend methods for agencies to incorporate the “social cost of carbon” into regulatory analyses and directed the United States Environmental Protection Agency (the "EPA") to review various environmental regulations for consistency with the policies and goals set forth in EO 13990. EO 14008 announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority. Ongoing legal challenges have slowed or halted the implementation of some of these directives, making it difficult to predict the full timing and extent to which federal agencies will implement them. The full impact of these federal actions, or any other future restrictions or prohibitions, remains unclear, but if such policies are implemented permanently (in part or in whole), these actions could have a material and negative financial impact on our business by reducing the areas in which we could operate.
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If new laws are enacted or other government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation, impose additional regulatory (including environmental protection) requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, or promote other sources of clean energy, our financial position, operating results and cash flows could be materially adversely affected. See "Item 1A. Risk Factors - Compliance with or breach of environmental laws could be costly and limit our operations."
Non-U.S. Operations
Revenues from non-U.S. operations were 78%, 87%, 81% and 83% of our total consolidated revenues during the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively.
See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."
Executive Officers
Officers generally serve for a one-year term or until successors are elected and qualified to serve. The table below sets forth certain information regarding our executive officers as of February 21, 2023:
| Name | Age | Position | ||||||||||||
| Anton Dibowitz | 51 | President and Chief Executive Officer | ||||||||||||
| Christopher Weber | 50 | Senior Vice President and Chief Financial Officer | ||||||||||||
| Gilles Luca | 51 | Senior Vice President and Chief Operating Officer | ||||||||||||
| Matthew Lyne | 48 | Senior Vice President and Chief Commercial Officer | ||||||||||||
| Davor Vukadin | 49 | Senior Vice President and General Counsel | ||||||||||||
Set forth below is certain additional information on our executive officers, including the business experience of each executive officer for at least the last five years:
Anton Dibowitz became the President and Chief Executive Officer of Valaris in December 2021, following his service as the Company’s interim President and Chief Executive Officer since September 2021. Mr. Dibowitz joined the Valaris board of directors in July 2021. Prior to joining the Valaris board of directors, he served as an advisor of Seadrill Ltd., a global offshore drilling contractor, from November 2020 until March 2021. He served as Chief Executive Officer of Seadrill Ltd. from July 2017 until October 2020. Prior to this Mr. Dibowitz served as Executive Vice President of Seadrill Management since June 2016, and as Chief Commercial Officer since January 2013. He has over 20 years of drilling industry experience. Prior to joining Seadrill, Mr. Dibowitz held various positions within tax, process reengineering and marketing at Transocean Ltd. and Ernst & Young LLP. He is a Certified Public Accountant and a graduate of the University of Texas at Austin where he received a Bachelor's degree in Business Administration, and Master's degrees in Professional Accounting (MPA) and Business Administration (MBA).
Christopher Weber became the Senior Vice President and Chief Financial Officer of Valaris in August 2022. Previously, he served as Chief Financial Officer of LUFKIN Industries, a leading global provider of rod lift optimization solutions, products, technologies and services to the oil and gas industry, from February 2021 to July 2022. Mr. Weber has also served as Chief Financial Officer of Abaco Drilling Technologies from July 2019 to February 2021 and Chief Financial Officer of Haliburton Company from June 2017 to November 2018. Prior to Halliburton, Mr. Weber served as Chief Financial Officer of Parker Drilling Company, and held senior finance roles at Valaris predecessor companies, Ensco plc and Pride International, Inc. He received an MBA in Finance and Strategy from the Wharton School and a BA in Economics and English Literature from Vanderbilt.
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Gilles Luca became Senior Vice President and Chief Operating Officer in December 2019. Previously, he served as Senior Vice President, Operations Support. He joined Ensco in 1997. Mr. Luca also served Ensco as Senior Vice President - Western Hemisphere, Vice President - Business Development and Strategic Planning, Vice President - Brazil Business Unit and General Manager - Europe and Africa. Before joining Ensco as an Operations Engineer in The Netherlands, Mr. Luca was employed by Foramer Drilling and Schlumberger with assignments in France and Venezuela. He holds a Master Degree in Petroleum Engineering from the French Petroleum Institute and a Bachelor in Civil Engineering.
Matthew Lyne became the Senior Vice President and Chief Commercial Officer of Valaris in September 2022. Previously, he served as Executive Vice President, Chief Commercial and Strategy Officer of Seadrill Limited from May 2021 to September 2022. Seadrill Limited filed for bankruptcy in February 2021. Prior to this role, he held a number of senior marketing and commercial roles at Seadrill Limited for more than 10 years. He also served in a number of senior operational and functional roles with Transocean Ltd. prior to joining Seadrill Limited. Mr. Lyne has over 20 years of offshore drilling experience in various international locations. Mr. Lyne has a Bachelor of Science degree in Engineering from Montana Technological University.
Davor Vukadin was appointed Senior Vice President, General Counsel and Secretary in May 2022. Before being named to his current position, Mr. Vukadin served as Associate General Counsel and Secretary from June 2021 to May 2022. Previously, he served as Associate General Counsel and Assistant Secretary from November 2018 to June 2021. He joined Valaris as Senior Counsel in 2014. Prior to joining Valaris, Mr. Vukadin practiced corporate and securities law with the law firm of Norton Rose Fulbright for thirteen years. He holds a Bachelor of Arts degree in Economics from The University of Chicago and a law degree from The University of Texas School of Law.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file with, or furnish to, the Securities and Exchange Commission ("SEC") in accordance with the Exchange Act are available free of charge on our website at www.valaris.com/investors. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The information contained on our website is not included as part of, or incorporated by reference into, this report.
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RISK FACTORS SUMMARY
An investment in our securities involves a high degree of risk. You should consider carefully all of the risks described below, together with the other information contained in this Form 10-K, before making a decision to invest in our securities. If any of the following events occur, our business, financial condition and operating results may be materially adversely affected. In that event, the trading price of our securities could decline, and you could lose all or part of your investment.
Risks Related to Our Business, Operations, Indebtedness and Market Conditions
•The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production, which can be significantly affected by volatile oil and natural gas prices.
•The offshore contract drilling industry is highly competitive and cyclical.
•Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.
•Our business will be materially adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.
•Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.
•The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could materially adversely affect our business.
•Our long-term contracts are subject to the risk of cost increases, which could adversely affect our profitability.
•Our information technology systems, including rig operating systems and critical data, are subject to cybersecurity risks.
•Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could materially adversely affect our financial position, operating results or cash flows.
•We make significant expenditures to meet customer requirements, maintain our fleet to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, and we may be required to make significant expenditures to maintain our competitiveness.
•Failure to recruit and retain skilled personnel could adversely affect our business.
•Our shared service center may not create the operational efficiencies that we expect and may create risks relating to the processing of transactions and recording of financial information.
•We may not realize the expected benefits of our ARO joint venture.
•Joint venture investments could be adversely affected by our joint venture partners' actions, financial condition and liquidity and disputes between us and our joint venture partners.
•Our business involves operating hazards, and our insurance and indemnities from our customers may not be adequate to cover any potential losses.
•Geopolitical events and violence could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.
•Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.
•The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations.
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•Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility with regard to the management of our personnel.
•Significant equipment or part shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could materially adversely affect our financial position, operating results or cash flows.
•Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues.
•Our ability to pay our operating and capital expenses and make payments due on our debt depends on many factors beyond our control.
•The Indenture (as defined below) governing the First Lien Notes contains provisions that could limit our business activities.
•Our actual financial results after emergence from bankruptcy may not be comparable to our projections filed with the Bankruptcy Court in the course of the Chapter 11 Cases.
•The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute the holders of our Common Shares.
Regulatory, Legal and Tax Risks
•Failure to comply with anti-corruption and anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, could result in fines, criminal penalties, drilling contract terminations and materially adversely affect our financial position, operating results or cash flows.
•Increasing regulatory complexity could adversely impact our offshore drilling operations and reduce demand.
•Compliance with or breach of environmental laws could be costly and limit our operations.
•The Internal Revenue Service ("IRS") may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.
•U.S. tax laws and IRS guidance could affect our ability to engage in certain transactions.
•Governments may pass laws that subject us to additional taxation or may challenge our tax positions.
•Our consolidated effective income tax rate may vary substantially over time.
•We are subject to litigation that could have a material adverse effect on us.
•The rights of our shareholders are governed under Bermuda law, and as a result, holders of our Common Shares may have difficulty enforcing civil judgments against us.
•Our bye-laws restrict shareholders from bringing legal action against our officers and directors.
•Provisions in our bye-laws could delay or prevent a change in control of our company.
•Legislation enacted in Bermuda as to Economic Substance may affect our operations.
•Our business could be affected as a result of activist investors.
Risks Related to Our International Operations
•Our non-U.S. operations involve additional risks not typically associated with U.S. operations.
ESG Risks
•Regulation of greenhouse gases and climate change could have a negative impact on our business.
•Consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition, may lead to reduced demand for our services.
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•Increased scrutiny from stakeholders and others regarding our ESG practices, initiatives and reporting responsibilities could result in additional costs or risks.
Item 1A. Risk Factors
Risks Related to Our Business, Operations, Indebtedness and Market Conditions
The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production, which can be significantly affected by volatile oil and natural gas prices.
The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of these prices, significantly affect the level of drilling activity. Historically, when operator capital spending declines, utilization and day rates also decline. The sharp decline in oil and natural gas prices resulting from the COVID-19 pandemic and the activities of OPEC+ caused a significant decline in both drilling activity and prices for our services in fiscal year 2020. While market conditions have improved, we have not experienced a multi-year period of higher sustained oil and natural gas prices. The lack of a sustained and stable recovery, price reductions or volatility in oil and natural gas prices may cause our customers to lower levels of capital spending or reduce their overall level of activity, in which case demand for our services may decline and revenues may be materially adversely affected through lower rig utilization and/or lower day rates.
Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:
•regional and global economic conditions and changes therein, including recessions,
•oil and natural gas supply and demand, which is affected by worldwide economic activity and population growth,
•expectations regarding future energy prices,
•the desire and ability of the Organization of Petroleum Exporting Countries ("OPEC"), its members and other oil-producing nations, such as Russia, to reach further agreements to set and maintain production levels and pricing and to implement existing and future agreements,
•the availability of capital for oil and natural gas participants, including our customers, and capital allocation decisions by our customers, including the relative economics of offshore development versus alternative prospects,
•the level of production by non-OPEC countries,
•U.S. and non-U.S. tax policy, including the U.K. windfall tax on oil and gas producers in the British North Sea,
•advances in exploration and development technology, including with respect to onshore shale,
•costs associated with exploring for, developing, producing and delivering oil and natural gas,
•the rate of discovery of new oil and natural gas reserves and the rate of decline of existing oil and gas reserves,
•investors reducing, or ceasing to provide, funding to the oil and natural gas industry in response to initiatives to limit climate change,
•laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development,
•the development and exploitation of alternative fuels or energy sources, resulting in reduced capital spending by our customers on oil and natural gas projects, and increased demand for electric-powered products, including electric-powered vehicles,
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•disruption to exploration and development activities due to hurricanes and other adverse weather conditions and the risk thereof,
•natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills,
•the worldwide military or political environment, including the invasion of Ukraine by Russia and any related political or economic responses, global macroeconomic effects of trade disputes and increased tariffs and sanctions and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas or geographic areas in which we operate, or acts of terrorism, and
•COVID-19 and related public health measures implemented by governments worldwide and the occurrence or threat of other epidemic or pandemic diseases, including variants of COVID-19, and any government response to such occurrence or threat.
Higher commodity prices may not necessarily translate into increased activity, however, and even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their expectations for future oil prices, the cost of exploration efforts, extended periods of price volatility, their lack of success in exploration efforts and re-allocating capital expenditures for renewable energy projects.
These factors could cause our revenues and profits to decline and limit our future growth prospects. Any significant decline in day rates or utilization of our drilling rigs could materially adversely affect our financial position, operating results and cash flows. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and obtain insurance coverage that we consider adequate or are otherwise required by our contracts.
The offshore contract drilling industry is highly competitive and cyclical.
Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a contract. Rig availability, location and technical capabilities also can be significant factors in the determination. If we are not able to compete successfully, our revenues and profitability may decline.
Demand for offshore contract drilling services is highly cyclical, which is primarily driven by the demand for drilling rigs and the available supply of drilling rigs. Demand for drilling rigs is driven by the levels of offshore exploration and development conducted by oil and natural gas companies, which is beyond our control and may fluctuate substantially from year-to-year and from region-to-region.
Prolonged periods of reduced demand or excess rig supply have required us, and may in the future require us, to idle, sell or scrap rigs and enter into low day rate contracts or contracts with unfavorable terms. There can be no assurance that the current demand for drilling rigs will increase in the future or that any short-term improvement to market conditions will be sustained. Any further decline in demand for drilling rigs or oversupply of drilling rigs could materially adversely affect our financial position, operating results or cash flows.
Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.
As of February 21, 2023 and 2022, our contract backlog was approximately $2.5 billion and $2.4 billion, respectively. This amount reflects the remaining contractual terms multiplied by the applicable contractual day rate. The contractual revenue may be higher than the actual revenue we ultimately receive because of a number of factors, including rig downtime or suspension of operations.
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Several factors could cause rig downtime or a suspension of operations, many of which are beyond our control, including the early termination, repudiation or renegotiation of contracts, breakdowns of equipment, work stoppages, including labor strikes, shortages of material or skilled labor, surveys or inspections by government and maritime authorities, periodic classification surveys, severe weather, strong ocean currents or harsh operating conditions, the occurrence or threat of epidemic or pandemic diseases, such as COVID-19, and any government response to such occurrence or threat and force majeure events.
Our customers may seek to terminate, repudiate or renegotiate our drilling contracts for various reasons, including in the event of damage or a total loss of the drilling rig, the suspension or interruption of operations for extended periods due to breakdown of major rig equipment, failure to comply with performance conditions or equipment specifications, the failure of the customer to receive final investment decision (FID) with respect to projects for which the drilling rig was contracted or other reasons and "force majeure" events beyond the control of either party or other specific conditions. Generally, our drilling contracts 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. In cases where customers are required to make an early termination payment, such payments would provide some level of compensation to us for the lost revenue from the contract but in many cases would not fully compensate us for all of the lost revenue. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.
A decline in oil prices and any resulting downward pressure on utilization may cause some customers to consider early termination of select contracts despite having to pay onerous early termination fees in certain cases. Customers may request to renegotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts. In addition, financially distressed customers may seek to negotiate reduced termination fees as part of a restructuring package. Furthermore, as contracts expire, we may be unable to secure new contracts for our drilling rigs. Therefore, revenues recorded in future periods could differ materially from our current backlog. Our inability to realize the full amount of our contract backlog or to secure a new contract with substantially similar terms on a timely basis could materially adversely affect our financial position, operating results or cash flows.
Our business will be materially adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.
Our ability to renew expiring contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. Our customers’ decisions to exercise option periods resulting in additional work for the rig under contract also depend on market conditions. We may be unable to renew our expiring contracts, including contracts expiring due to a failure by the customer to exercise option periods, or obtain new contracts for the drilling rigs under contracts that have expired or have been terminated, and the day rates under any new contracts or any renegotiated contracts may be substantially below the existing day rates, which could materially adversely affect our financial position, operating results or cash flows. If customers do not exercise option periods under contracts that we currently expect to be exercised, we may face increased idle time associated with the related rig, as we may have difficulty securing additional work to cover the option period. In addition, we may choose to stack idle rigs that are not under contract, which would require us to incur stacking costs for such rigs.
Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.
Some of our customers may be subject to liquidity risk that could lead them to seek to repudiate, cancel or renegotiate our drilling contracts or fail to fulfill their commitments to us under those contracts. These risks are heightened in periods of depressed market conditions. Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising from the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is allocated so that we and our customers each assume liability for our respective personnel and property. Our customers have historically assumed most of the responsibility for, and indemnified us from loss, damage or other liability resulting from, pollution or contamination, including clean-
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up and removal, and third-party damages arising from operations under the contract when the source of the pollution originates from the well or reservoir, including those resulting from blowouts or cratering of the well. However, we regularly are required to assume a limited amount of liability for pollution damage caused by our negligence, which liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence or willful misconduct. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to fulfill their indemnification obligations to us for such losses. In addition, under the laws of certain jurisdictions, such indemnities under certain circumstances are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in us having to assume liabilities in excess of those agreed in our contracts due to customer balance sheet or liquidity issues or applicable law.
The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could materially adversely affect our business.
We provide our services to major international, government-owned and independent oil and natural gas companies. During 2022, our five largest customers accounted for 43% of consolidated revenues, with our largest customer representing 15% of our consolidated revenues and a significant percentage of our operating cash flows. Our financial position, operating results or cash flows may be materially adversely affected if any of our higher day rate contracts were terminated or renegotiated on less favorable terms or if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.
Some of our customers have consolidated and could continue to consolidate and could use their size and purchasing power to achieve economies of scale and pricing concessions. In addition, certain of our customers are increasingly focusing their business strategy on renewable energy projects and away from oil and natural gas exploration and production. Such customer consolidation and strategic transitions could result in reduced capital spending by such customers, decreased demand for our drilling services, loss of competitive position and negative pricing impacts. If we cannot maintain service and pricing levels for existing customers or replace such revenues with increased business activities from other customers, our financial position, operating results and cash flows could be materially adversely affected.
Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability.
In general, our costs increase as the demand for contract drilling services and skilled labor increase, which may materially adversely affect our financial position, operating results or cash flows. Our long-term contracts are subject to inflationary factors such as increases in skilled labor costs, material costs and overhead costs. While some of our contracts include cost escalation provisions that allow changes to our day rate based on stipulated cost increases or decreases, the timing and amount earned from these day rate adjustments may differ from our actual increase in costs and many contracts do not allow for such day rate adjustments. During times of reduced demand, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels in a particular geographic location and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity a drilling rig is performing and the age and condition of the equipment, as well as the impact of supply chain disruptions and inflation on the costs of parts and materials. Contract preparation expenses vary based on the scope and length of contract preparation required.
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Our information technology systems, including rig operating systems and critical data, are subject to cybersecurity risks.
We depend on technologies, systems and networks to conduct our offshore operations and help run our financial and onshore operations functions, including the collection of payments from customers, payments to vendors and employees and storage of company records. Our information technology and infrastructure may fail or be subject to flaws that could adversely impact our business. In addition, despite our security measures, we could be vulnerable to attacks by third-parties or breaches due to employee error, malfeasance or other disruptions. The risks associated with the failure of our computer systems and cyber incidents and attacks on our information technology systems could include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations, including disruptions in our ability to make or receive payments and financial and onshore operating functions, loss of intellectual property, proprietary information, customer and vendor data or other sensitive information; corruption or unauthorized release of our or our customer’s critical data; disruption of our or our customers' operations; and increased costs to prevent, respond to or mitigate cybersecurity events. Any such breach or attack could result in injury to people, loss of control of, or damage to, our, or our customer's, assets, downtime, loss of revenue or harm to the environment. Any such breach or attack could also compromise our networks or our customers' and vendors' networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in significant fines, civil and/or criminal claims or proceedings. Laws and regulations governing data privacy and the unauthorized disclosure of confidential or protected information, including the European Union General Data Protection Regulation, pose increasingly complex compliance challenges and potential costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. Disruption to our operations and damage to our reputation could materially adversely affect our financial position, operating results or cash flows. There can also be no assurance that our efforts, or the efforts of our partners and vendors, to invest in the protection of information technology infrastructure and data will prevent or identify breaches in our systems.
Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could materially adversely affect our financial position, operating results or cash flows.
The costs required to reactivate a stacked rig and return the rig to drilling service are significant. Depending on the length of time that a rig has been stacked, we may incur significant costs to restore the rig to drilling capability, which may also include capital expenditures due to, among other things, technological obsolescence or an equipment overhaul of the rig. Stacked drilling rigs require expenditures to return these rigs to drilling service. In the future, market conditions may not justify these types of expenditures or enable us to operate our rigs profitably during the remainder of their economic lives. In addition, we may not recover the expenditures incurred to reactivate rigs through the associated drilling contract or otherwise. We can provide no assurance that we will have access to adequate or economical sources of capital to fund the return of stacked rigs to drilling service.
During periods of increased rig reactivation, upgrade and enhancement projects, shipyards and third-party equipment vendors may be under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays, equipment failures and/or quality deficiencies. Furthermore, drilling rigs may face start-up or other operational complications following completion of upgrades or maintenance. Other unexpected difficulties, including equipment failures, design or engineering problems, could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.
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Rig reactivation, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns, including the following: failure of third-party equipment to meet quality and/or performance standards, delays in equipment deliveries or shipyard construction, shortages of materials or skilled labor, disruptions occurring as the result of pandemics and/or epidemics and related public health measures implemented by governments worldwide, damage to shipyard facilities, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities, unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment, unanticipated actual or purported change orders, strikes, labor disputes or work stoppages, financial or operating difficulties of equipment vendors or the shipyard while enhancing, upgrading, improving or repairing a rig or rigs, unanticipated cost increases, foreign currency exchange rate fluctuations impacting overall cost, inability to obtain the requisite permits or approvals, client acceptance delays, disputes with shipyards and suppliers, latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, claims of force majeure events, and additional risks inherent to shipyard projects in a non-U.S. location. These risks could result in the cancellation or termination of drilling contracts for which the drilling rig was contracted or reduce the likelihood that such drilling rigs will receive a drilling contract if not already contracted.
We make significant expenditures to meet customer requirements, maintain our fleet to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, and we may be required to make significant expenditures to maintain our competitiveness.
We make substantial expenditures to maintain our fleet. These expenditures could increase as a result of changes in offshore drilling technology, the cost of labor and materials, customer requirements, fleet size, the cost of replacement parts for existing drilling rigs, the geographic location of the drilling rigs, length of drilling contracts, governmental regulations, maritime regulations and technical standards relating to safety, security or the environment, and industry standards.
Changes in offshore drilling technology, customer requirements for new or upgraded equipment, and competition within our industry may require us to make significant capital expenditures. In addition, changes in governmental regulations relating to decarbonization, environmental, emissions, safety or equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. In addition, commitments made by us, or our customers, to reduce emissions, or decarbonize, may require us to upgrade or retrofit our drilling rigs with additional equipment, less carbon intensive equipment or instrumentation. As a result, we may be required to take our drilling rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our drilling rigs profitably during the remainder of their economic useful lives.
Additionally, in order to expand our fleet, we may require additional capital in the future. If we are unable to fund capital requirements with cash flows from operations or proceeds from sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by restrictive covenants in our debt agreements, bye-laws and regulations and by adverse market conditions resulting from, among others, general economic conditions, contingencies and uncertainties that are beyond our control. Similarly, when lenders and institutional investors reduce, and in some cases cease to provide, funding to industry borrowers, the liquidity and financial condition of us and our customers can be adversely impacted. If we raise funds by issuing equity securities, existing shareholders may experience dilution, and if we raise funds by issuing additional debt securities, we may have to pledge additional assets as collateral. Our failure to obtain the funds for necessary future capital expenditures could materially adversely affect our business and on our financial position, operating results or cash flows.
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Failure to recruit and retain skilled personnel could materially adversely affect our business.
We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business, and our rig reactivation program will require that we hire additional skilled personnel. As demand for our services and the number of active drilling rigs has increased, competition for the labor required for drilling operations and construction projects has intensified, potentially leading to shortages of qualified personnel in the industry. During such periods of intensified competition, it is more difficult and costly to recruit, train and retain qualified employees, including in foreign countries that require a certain percentage of national employees. We may also face a loss of workers and labor shortages as a result of requirements and enforcement of COVID-19 regulations in jurisdictions where we operate. The recent prolonged industry downturn and reductions in offshore personnel wages further reduced the number of qualified personnel available. Hiring qualified and experienced personnel with the specialized skills and qualifications required to operate an offshore drilling rig is difficult due to the competitive labor market and lack of experience. In an environment where competition for labor is intense, we may be required to increase existing levels of compensation to stay competitive in retaining a skilled workforce.
In addition, new personnel that we hire may need to undergo training to develop the skills needed to perform their job duties. There can be no assurance that our training programs will be adequate for these purposes, which could expose us to operational hazards and risks. We may also incur additional training costs to ensure that new or promoted personnel have the right skills and qualifications.
We also are subject to potential legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment, including mandated vaccination programs. These conditions could further increase our costs or limit our ability to fully staff and operate our drilling rigs.
The increases in employment costs cause an increase in operating expenses, with a resulting reduction in net income, and our ability to fully staff and operate our drilling rigs may be negatively affected.
Our shared service center may not create the operational efficiencies that we expect and may create risks relating to the processing of transactions and recording of financial information, which could materially adversely affect our financial condition, operating results or cash flows.
We have implemented a shared service center program pursuant to which we have outsourced certain finance, human resources, supply chain and IT functions. We have and will continue to align the design and operation of our financial control environment as part of our shared service center program. As part of this program, we are outsourcing, and will continue to outsource, certain accounting, payroll, human resources, supply chain and IT functions to a third-party service provider. The party that we utilize for these services may not be able to handle the volume of activity or perform the quality of service necessary to support our operations. The failure of the third-party to fulfill its obligations could disrupt our operations. In addition, the move to a shared service environment, including our reliance on a third-party provider, may create risks relating to the processing of transactions and recording of financial information. We could experience a lapse in the operation of internal controls due to turnover, lack of legacy knowledge, inappropriate training and use of a third-party provider, which could result in significant deficiencies or material weaknesses in our internal control over financial reporting and materially adversely affect our financial position, operating results or cash flows.
We may not realize the expected benefits of our ARO joint venture.
ARO, our 50/50 unconsolidated ARO joint venture and a provider of offshore drilling services, faces many of the same risks as we face. Operating through ARO, in which we have a shared interest, may result in our having less control over many decisions made with respect to projects, operations, safety, utilization, internal controls and other operating and financial matters. ARO may not apply the same controls and policies that we follow to manage our risks, and ARO’s controls and policies may not be as effective. As a result, operational, financial and control issues may arise, which could materially adversely affect our financial position, operating results or cash flows. Additionally, in order to establish or preserve our relationship with our joint venture partner we may agree to risks
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and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in ARO compared to what we may traditionally require in other areas of our business.
ARO’s income and accounts receivable are concentrated with Saudi Aramco. The loss of this customer, or a substantial decrease in demand by this customer for ARO’s services, would have a material adverse effect on ARO’s business, results of operations and financial condition, which could materially adversely affect our financial position, operating results or cash flows.
We have issued a 10-year shareholder notes receivable to ARO (the "Notes Receivable from ARO"), which are governed by the laws of Saudi Arabia. In the event of a dispute with ARO over the repayment of the Notes Receivable from ARO, our ability to enforce the payment obligations of ARO or to exercise other remedies are subject to several significant limitations, including that our ability to accelerate outstanding amounts under the Notes Receivable from ARO is subject to the consent of Saudi Aramco and that the Notes Receivable from ARO are governed by the laws of Saudi Arabia, and we are limited to the remedies available under Saudi law.
We have a potential obligation to fund ARO for newbuild jackup rigs. ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups. While the shipyard contract contemplated that these newbuild rigs would be delivered in 2022, the delivery of the rigs has been delayed into 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. There can be no assurance that the new jackup rigs will begin operations as anticipated. Further, in the event ARO has insufficient cash from operations or is unable to obtain third-party financing, we may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion under the ARO shareholders’ agreement. Any required capital contributions we make could negatively impact our liquidity position and financial condition.
As a result of these risks, it may take longer than expected for us to realize the expected returns on our investment in ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and could materially adversely affect our financial position, operating results or cash flows.
Joint venture investments could be adversely affected by our joint venture partners’ actions, financial condition and liquidity and disputes between us and our joint venture partners.
We have made investments in joint ventures other than ARO. Such investments are subject to the risk that the other shareholders of the joint venture, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to block business, financial, or management decisions (such as the decision to distribute dividends or appoint members of management), which may be crucial to the success of our investment in the joint venture, or could otherwise implement initiatives which may be contrary to our interests. Our partners may be unable, or unwilling, to fulfil their obligations under the relevant agreements regarding such joint ventures (for example by non-contributing working capital or other resources), or may experience financial, operational, or other difficulties that may adversely impact our investment in a particular joint venture. In addition, our partners may lack sufficient controls and procedures which could expose us to risk. If any of the foregoing were to occur, such occurrence could materially adversely affect our financial position, operating results or cash flows.
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We may pursue other joint ventures that we believe will enable us to further expand or enhance our business. Any such joint venture would be evaluated on a case-by-case basis, and its consummation would depend upon numerous factors, including identifying suitable opportunities that align with our business strategy, reaching agreement with the potential counterparty on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions. Any such joint venture would involve various risks, including among others (1) difficulties related to integrating or managing applicable parts of a joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing, (2) diversion of management’s attention from day-to-day operations, (3) failure to realize anticipated benefits, such as cost savings, revenue enhancements or business synergies, (4) the potential for substantial transaction expenses and (5) potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time any such transaction is consummated.
Our business involves operating hazards, and our insurance and indemnities from our customers may not be adequate to cover any potential losses.
The drilling of oil and natural gas wells involves numerous operating hazards, such as blowouts, reservoir damage, loss of production, loss of well control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punch throughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and other parties or prosecution by governmental authorities. These hazards can cause personal injury or loss of life, severe damage to, or destruction of, property and equipment, pollution or environmental damage, which could lead to claims by employees, contractors or third parties and suspension of operations and contract terminations. Our drilling rigs are also subject to hazards associated with marine operations, either while docked, on site or during mobilization, such as capsizing, breaking free of moorings, sinking, grounding, collision, piracy, damage from adverse weather and marine life infestations. The U.S. Gulf of Mexico and the coasts of Australia are areas subject to hurricanes, typhoons and other adverse weather conditions, and our drilling rigs in these regions may be exposed to damage or a total loss by these storms, some of which may not be covered by insurance. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. Damage to the environment could also result from our operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations or fires. We may also be subject to property damage, environmental indemnity and other claims by third parties. Drilling involves certain risks associated with the loss of control of a well, such as blowout, cratering, the cost to regain control of or redrill the well and remediation of associated pollution. Our customers may be unable or unwilling to indemnify us against such risks. In addition, a court may decide that certain indemnities in our current or future drilling contracts are not enforceable. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy, and the enforceability of an indemnity as to other matters may be limited.
Our insurance policies and drilling contracts contain rights to indemnity that may not adequately cover our losses, and we do not have insurance coverage or rights to indemnity for all risks. We have two main types of insurance coverage: (1) hull and machinery coverage for physical damage to our property and equipment and (2) excess liability coverage, which generally covers our liabilities arising from our operations, such as personal injury and property claims, including wreck removal and pollution. We have no hull and machinery insurance coverage for damages caused by named storms in the U.S. Gulf of Mexico for our jack-up fleet and only limited coverage for our floater fleet. We also retain the risk for any liability that exceeds our excess liability coverage. Pollution and environmental risks generally are not completely insurable.
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If a significant accident or other event occurs that is not fully covered by our insurance or by an enforceable or recoverable indemnity, the occurrence could materially adversely affect our financial position, operating results or cash flows. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we generally retain the risk for any losses in excess of these limits. We currently do not carry insurance for loss of revenue, and certain other claims may also not be reimbursed by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain more risk in the future, resulting in higher risk of losses, which could be material. Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable or be able to obtain insurance against certain risks. Furthermore, our insurance carriers may assert that our insurance policies do not provide coverage for our losses. Our insurance policies also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, loss of hire and losses relating to terrorist acts or strikes and some cyber events. As a result of increased costs to insurance companies due to regulatory, geopolitical, reputational or other developments, insurance companies that have historically participated in underwriting risks arising out of oil and natural gas operations may discontinue that practice, may reduce the insurance capacity they are willing to deploy or demand significantly higher premiums or deductibles to cover these risks. Additionally, a significant number of high cost climate-related insurance claims or natural catastrophes such as floods or windstorms may result in withdrawal of insurance capacity and increasing premiums to oil and natural gas industry companies.
Geopolitical events and violence could materially adversely affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.
Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses to such events. Military action by the U.S. or other nations could escalate, and acts of terrorism, piracy, kidnapping, extortion, acts of war, violence, civil war or general disorder may initiate or continue. Such acts could be directed against us or our assets. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could materially adversely affect the markets for our services, particularly to the extent that such events take place in regions with significant oil and natural gas reserves, refining facilities or transportation infrastructure. For example, the ongoing conflict, and the continuation of, or any increase in the severity of, the conflict between Russia and Ukraine, has led and may continue to lead to an increase in the volatility of global oil and natural gas prices. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could materially adversely affect our financial position, operating results or cash flows.
Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.
We currently own and operate 13 drilling rigs that are contracted with national oil companies. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability, personal injury and other claims for damages (including consequential damages), or, in certain cases, the risk of early termination of the contract for convenience (without cause), exercisable upon advance notice to us, contractually or by governmental action, without making an early termination payment to us. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of drilling rigs contracted to national oil companies with commensurate additional contractual risks.
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The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations.
Public health crises, pandemics and epidemics, such as the COVID-19 pandemic, and fear of such events have adversely impacted and may continue to adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Other effects of such public health crises, pandemics and epidemics, including the COVID-19 pandemic, have included and may continue to include, significant volatility and disruption of the global financial markets; continued volatility of crude oil prices and related uncertainties around OPEC+ production; disruption of our operations, including suspension of drilling activities; impact to costs; loss of workers; labor shortages; supply chain disruptions or equipment shortages; logistics constraints; customer demand for our services and industry demand generally; capital spending by oil and natural gas companies; our liquidity; the price of our securities and trading markets with respect thereto; our ability to access capital markets; asset impairments and other accounting changes; certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us; and employee impacts from illness, travel restrictions, including border closures and other community response measures. Such public health crises, pandemics and epidemics are continuously evolving and the extent to which our business operations and financial results continue to be affected depends on various factors beyond our control, such as the duration, severity and sustained geographic resurgence of the COVID-19 virus; the emergence, severity and spread of new variants of the COVID-19 virus; the impact and effectiveness of governmental actions to contain and treat such outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility with regard to the management of our personnel.
Outside of the U.S., we are often subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our profitability or limit our flexibility.
Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our financial position, operating results or cash flows.
Significant equipment or part shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could materially adversely affect our financial position, operating results or cash flows.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Industry consolidation has reduced and may continue to reduce the number of available suppliers, and our suppliers have been and may continue to be impacted by supply chain and logistics disruptions that began during the COVID-19 pandemic. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, including those related to inflation and supply chain disruption, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers by making it cost prohibitive to do so, thus adversely impacting our operations and revenues and/or our operating costs. Delays in the delivery of critical drilling equipment could cause delays in the expected timing of rig
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reactivation, enhancement or upgrade projects, unscheduled operational downtime, our drilling rigs to be unavailable within the commencement window established by the operator in the contract and subject us to potential termination of the contract for such late delivery of the drilling rig.
Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues.
Our operating and maintenance costs will not necessarily be proportional to changes in our operating revenues. Operating costs are affected by many factors, including inflation, while maintenance costs depend on, among other factors, market conditions for drilling services as well as unplanned downtime events or idle periods between contracts. Costs for operating a rig are therefore generally not correlated to the day rate being earned. As our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. Equipment maintenance costs fluctuate depending upon the age and condition of the equipment, and these costs could increase for short or extended periods as a result of new regulatory or customer requirements. In addition, certain of our drilling contracts are partially payable in local currency. The amounts, if any, of local currency received under these drilling contracts may exceed our local currency needs to pay local operating and maintenance costs, leading to an accumulation of excess local currency balances, which, in certain instances, may be subject to either restrictions or other difficulties in converting to U.S. dollars, our functional currency, or to other currencies of the locations where we operate. Excess amounts of local currency may also expose us to the risk of currency exchange losses.
Our ability to pay our operating and capital expenses and make payments due on our debt depends on many factors beyond our control.
Our ability to pay our operating and capital expenses and make payments due on our debt depends on our future performance, which will be affected by financial, business, economic, legislative and other factors, many of which are beyond our control. Our business may not generate sufficient cash flow from operations in the future, which could result in our being unable to fund liquidity needs or repay indebtedness. A range of economic, business and industry factors will affect our financial performance, and many of these factors, such as the condition of our industry, the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as selling assets; reducing or delaying capital investments; seeking to raise additional capital; or restructuring or refinancing all or a portion of our indebtedness at or before maturity.
We cannot be assured that we will be able to accomplish any of these alternatives on terms acceptable to us or at all. In addition, the terms of existing or future debt agreements may restrict us from adopting any of these alternatives. The failure to generate sufficient cash flow or to achieve any of these alternatives could materially adversely affect our ability to fund liquidity needs or pay amounts due under our debt.
The indenture dated April 30, 2021 (the "Indenture") governing the First Lien Notes contains provisions that restrict our business and financing activities and could limit our business activities.
The restrictive covenants in the Indenture limit our ability to, among other things, incur certain types of additional indebtedness or issue certain types of preferred shares; sell or convey certain assets; make loans to or investments in others; enter into mergers; engage in transactions with affiliates; make certain payments; incur additional liens; and pay dividends or repurchase Common Shares.
These restrictive covenants restrict the manner in which we conduct our business, and we may be unable to engage in favorable business activities, take advantage of business opportunities or finance future operations or capital needs. A failure to comply with these restrictive covenants, as well as the other covenants under the First Lien Notes, would result in an event of default, which, if not cured or waived, would cause some or all of our indebtedness to become immediately due and payable and could materially adversely affect our financial position, operating results or cash flows.
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Our actual financial results after emergence from bankruptcy may not be comparable to our projections filed with the Bankruptcy Court in the course of the Chapter 11 Cases.
In connection with the disclosure statement we filed with the Bankruptcy Court and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from the Chapter 11 Cases. Those projections were prepared solely for the purpose of the Chapter 11 Cases and have not been and will not be updated and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to then prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. We have not updated the projections prepared solely for the purpose of our Chapter 11 Cases or the assumptions on which they were based after our emergence. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks, and the assumptions underlying the projections or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.
The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute the holders of our Common Shares.
On the Effective Date, we issued 75.0 million Common Shares and 5.6 million warrants to purchase 5.6 million Common Shares at an exercise price of $131.88 per share, exercisable for a seven-year period commencing on that date. Additionally, on May 3, 2021, our board of directors approved and ratified the Valaris Limited 2021 Management Incentive Plan (the “MIP”) and reserved 9.0 million of our Common Shares for issuance under the MIP primarily for employees and directors. The grant and vesting of equity awards in the future, any exercise of the warrants into Common Shares and any sale of Common Shares underlying outstanding warrants would have a dilutive effect to the holdings of our existing shareholders and could have a material adverse effect on the market for our Common Shares, including the price that an investor could obtain for their Common Shares.
Regulatory, Legal and Tax Risks
Failure to comply with anti-corruption and anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, could result in fines, criminal penalties, drilling contract terminations and materially adversely affect our financial position, operating results or cash flows.
We operate in a number of countries throughout the world, including countries known to have a reputation for corruption and are subject to the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”), the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") regulations, the U.K. Bribery Act ("UKBA"), other U.S. laws and regulations governing our international operations and similar laws in other countries.
In August 2017, one of our Brazilian subsidiaries was contacted by the Office of the Attorney General for the Brazilian state of Paraná in connection with a criminal investigation procedure initiated against agents of both Samsung Heavy Industries, a shipyard in South Korea (“SHI”), and Pride International LLC ("Pride") in relation to the drilling services agreement with Petrobras for the DS-5 (the "DSA"). The Brazilian authorities requested information regarding our compliance program and the findings of our internal investigations relating to the DSA. We cooperated with the Office of the Attorney General and provided documents in response to its request. We cannot predict the scope or ultimate outcome of this procedure or whether any Brazilian governmental authority will open an investigation into Pride’s involvement in this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation.
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Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws by us, our partners, agents and our and their respective affiliated entities or respective officers, directors, employees and agents could in some cases provide a customer with termination rights and other remedies under the terms of their contracts(s) with us and also result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and could materially adversely affect our financial condition, operating results or cash flows. Further, we may incur significant costs and consume significant internal resources in our efforts to detect, investigate and resolve actual or alleged violations.
Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations and reduce demand.
The offshore contract drilling industry is dependent on demand for services from the oil and natural gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could materially adversely affect our financial position, operating results or cash flows by limiting drilling opportunities. In recent years, we have seen several significant regulatory changes that have affected the way we operate in the U.S. Gulf of Mexico. See “Item 1. Business – Governmental Regulations and Environmental Matters.”
Any new or additional regulatory, legislative, permitting or certification requirements in the U.S., including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial position, operating results or cash flows.
We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors when operators fail to comply with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.
Compliance with or breach of environmental laws can be costly and could limit our operations.
Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment. However, the legislative, judicial and regulatory response to a well incident could substantially increase our and our customers' liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry. See “Item 1. Business – Governmental Regulations and Environmental Matters.”
ESG initiatives and high profile and catastrophic events, including the 2010 Macondo well incident, have increased the regulation of offshore oil and natural gas drilling. We are adversely affected by restrictions on drilling in certain areas in which we operate, including policies and guidelines regarding the approval of drilling permits, restrictions on development and production activities, and directives and regulations that have and may further
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impact our operations. From time to time, legislative and regulatory proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas, or that would increase the liabilities or costs associated with offshore drilling. If new laws are enacted, or if government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation or that impose environmental or other requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development, or production of oil and natural gas, our financial position, operating results or cash flows could be materially adversely affected.
The IRS may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.
Although Valaris Limited is incorporated in Bermuda (and thus would generally be considered a “foreign” corporation (or non-U.S. tax resident)), the U.S. Internal Revenue Service (“IRS”) could assert that we should be treated as a U.S. corporation (and U.S. tax resident) pursuant to the rules under Section 7874 of the Internal Revenue Code. While we do not believe we are a U.S. corporation pursuant to these rules, the rules are complex and the determination is subject to factual uncertainties. If the IRS successfully challenged our status as a foreign corporation, significant adverse tax consequences would result for us and for certain of our shareholders.
U.S. tax laws and IRS guidance could affect our ability to engage in certain acquisition strategies and certain internal restructurings.
Even if we were to be considered a foreign corporation for U.S. federal income tax purposes, Section 7874 of the Internal Revenue Code and U.S. Treasury Regulations promulgated thereunder, including temporary Treasury Regulations, may materially adversely affect our ability to engage in certain future acquisitions of U.S. businesses in exchange for our equity, which may affect the tax efficiencies that otherwise might be achieved in such potential future transactions.
Governments may pass laws that subject us to additional taxation or may challenge our tax positions.
There is increasing uncertainty with respect to tax laws, regulations and treaties, and the interpretation and enforcement thereof that may affect our business. The Organization for Economic Cooperation and Development (“OECD”) has issued its final reports on base erosion and profit shifting, which generally focus on situations where profits are earned in low-tax jurisdictions, or payments are made between affiliates from jurisdictions with high tax rates to jurisdictions with lower tax rates. Certain countries within which we operate have recently enacted changes to their tax laws in response to the OECD recommendations or otherwise and these and other countries may enact changes to their tax laws or practices in the future (prospectively or retroactively), which may have a material adverse effect on our financial position, operating results or cash flows. On December 12, 2022 the European Union member states agreed to implement the OECD’s Pillar 2 global corporate minimum tax rate of 15% on companies with revenues of at least $790 million, which would go into effect in 2024. Other countries including the United Kingdom, Switzerland, Canada, Australia and South Korea are also actively considering changes to their tax laws to adopt certain parts of the OECD’s proposals. U.S. federal income tax reform legislation enacted in late 2017 introduced significant changes to U.S. income tax law, including a reduction in the statutory income tax rate from 35% to 21%, a one-time transition tax on deemed repatriation of deferred foreign income, a base erosion anti-abuse tax that effectively imposes a minimum tax on certain payments to non-U.S. affiliates, new and revised rules relating to the current taxation of certain income of foreign subsidiaries and revised rules associated with limitations on the deduction of interest.
In addition, our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our tax positions, we may incur significant expenses in defending our positions and contesting claims asserted by tax authorities. If we are unsuccessful in defending our tax positions, the resulting assessments or rulings could significantly impact our consolidated income taxes in past or future periods.
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As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We are currently subject to tax assessments in various jurisdictions, which we are contesting.
As a result of these uncertainties, as well as changes in the administrative practices and precedents of tax authorities or other matters (such as changes in applicable accounting rules) that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements, we cannot provide any assurances as to what our consolidated effective income tax rate will be in future periods. If we are unable to mitigate the negative consequences of any change in law, audit or other matters, this could cause our consolidated income taxes to increase and materially adversely affect our financial position, operating results or cash flows.
Our consolidated effective income tax rate may vary substantially over time.
We cannot provide any assurances as to what our future consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or other matters (such as changes in applicable accounting rules) that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. In periods of declining profitability, our income tax expense may not decline proportionately with income. Further, we may continue to incur income tax expense in periods in which we operate at a loss. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matters, this could cause our consolidated effective income tax rate to increase and materially adversely affect our financial position, operating results or cash flows.
We are subject to litigation that could have a material adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, toxic tort claims, environmental claims or proceedings, employment matters, issues related to employee or representative conduct, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend or pursue such matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation could materially adversely affect our financial position, operating results or cash flows because of potential negative outcomes, legal fees, the allocation of management’s time and attention, and other factors.
We could also face increased climate-related litigation with respect to our operations both in the U.S. and around the world. Governmental and other entities in various states, such as California and New York, have filed lawsuits against coal, oil and natural gas companies. These suits allege damages as a result of climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions both in the U.S. and globally. Though we are not currently a party to any such lawsuit, these suits present uncertainty regarding the extent to which companies who are not producing oil or natural gas, but who are engaged to provide services to support production activities, such as offshore drillers, face an increased risk
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of liability stemming from climate change, which risk would also adversely impact the oil and natural gas industry and impact demand for our services.
We are a Bermuda company and it may be difficult to enforce judgments against us or our directors and executive officers.
We are a Bermuda exempted company. As a result, the rights of holders of our Common Shares are governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors and officers are not residents of the U.S., and a substantial portion of our assets are located outside the U.S. As a result, it may be difficult for investors to effect service of process on those persons in the U.S. or to enforce in the U.S. judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the U.S., against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.
Our bye-laws restrict shareholders from bringing legal action against our officers and directors.
Our bye-laws contain a broad waiver by our shareholders of any claim or right of action, both individually and on our behalf, against any of our officers or directors. The waiver applies to any action taken by an officer or director, or the failure of an officer or director to take any action, in the performance of his or her duties, except with respect to any matter involving any fraud or dishonesty on the part of the officer or director. This waiver limits the right of shareholders to assert claims against our officers and directors unless the act or failure to act involves fraud or dishonesty.
Provisions in our bye-laws could delay or prevent a change in control of our company, which could materially adversely affect the price of our Common Shares.
The existence of some provisions in our bye-laws could delay or prevent a change in control of our company that a shareholder may consider favorable, which could materially adversely affect the price of our Common Shares. Certain provisions of our bye-laws could make it more difficult for a third-party to acquire control of our company, even if the change of control would be beneficial to our shareholders. These provisions include:
•authority of our board of directors to determine its size;
•the ability of our board of directors to issue preferred shares without shareholder approval;
•limitations on the removal of directors; and
•limitations on the ability of our shareholders to act by written consent in lieu of a meeting.
In addition, our bye-laws establish advance notice provisions for shareholder proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders.
Legislation enacted in Bermuda as to Economic Substance may affect our operations.
The Economic Substance Act came into effect in Bermuda on January 1, 2019. This new law requires a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda that carries as a business any one or more of the “relevant activities” must comply with economic substance requirements. The Economic Substance Act may require in-scope Bermuda entities, which are engaged in such “relevant activities,” to be directed and managed in Bermuda, have an adequate level of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing and leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities. The Economic Substance Act
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could affect the manner in which we operate our business. To the extent we or any of our Bermuda subsidiaries carry on any relevant activities for the purposes of the Economic Substance Act, we or such subsidiaries will be required to comply with such economic substance requirements. Our compliance with the Economic Substance Act may result in additional costs that could have a material adverse effect on our financial position or results of operations.
Our business could be affected as a result of activist investors.
Publicly traded companies have increasingly become subject to campaigns by activist investors advocating corporate actions such as actions related to ESG matters, financial restructuring, increased borrowing, dividends, share repurchases or sales of assets or even the entire company. Responding to proxy contests and other actions by such activist investors or others in the future could be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of our business strategies, which could materially adversely affect our financial position, operating results or cash flows. Additionally, perceived uncertainties as to our future direction as a result of investor activism or changes to the composition of the board of directors may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our financial position, operating results or cash flows could be materially adversely affected. In addition, the trading price of our shares could experience periods of increased volatility as a result of investor activism.
Risks Related to Our International Operations
Our non-U.S. operations involve additional risks not typically associated with U.S. operations.
Revenues from non-U.S. operations were 78%, 87%, 81% and 83% of our total consolidated revenues for the year ended December 31, 2022 (Successor), during eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and year ended December 31, 2020 (Predecessor), respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:
•terrorist acts, war and civil disturbances,
•expropriation, nationalization, deprivation or confiscation of our equipment or our customer's property,
•repudiation or nationalization of contracts,
•assaults on property or personnel,
•piracy, kidnapping and extortion demands,
•significant governmental influence over many aspects of local economies and customers,
•unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,
•work stoppages, often due to strikes over which we have little or no control,
•complications associated with repairing and replacing equipment in remote locations,
•limitations on insurance coverage, such as war risk coverage, in certain areas,
•imposition of trade barriers,
•wage and price controls,
•import-export quotas,
•exchange restrictions, currency fluctuations and changes in monetary policy,
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•uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America, Southeastern Asia, Eastern Europe or other geographic areas in which we operate,
•changes in the manner or rate of taxation,
•limitations on our ability to recover amounts due,
•increased risk of government and vendor/supplier corruption,
•increased local content requirements,
•the occurrence or threat of epidemic or pandemic diseases (including the COVID-19 pandemic) and any government response to such occurrence or threat,
•changes in political conditions, and
•other forms of government regulation and economic conditions that are beyond our control.
We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, expropriation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries. In circumstances where we have insurance protection for some or all of the risks associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we would be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for which we have not received an enforceable contractual indemnity from a customer, could materially adversely affect our financial position, operating results or cash flows.
We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing or changes in the administrative practices and precedents of tax authorities, adverse rulings in connection with audits or otherwise, or other challenges may have a material impact on our tax expense.
Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Governments in some countries are active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding such concessions, the exploration of oil and natural gas and other aspects of the oil and natural gas industry in their countries. In some areas of the world, government activity has materially adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not materially adversely affect our financial position, operating results or cash flows.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by specific customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
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The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime, reduced day rates during such downtime and contract cancellations. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.
Our partners, agents and our and their respective affiliated entities or respective officers, directors, employees and agents may take actions in violation of our policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate. Any such violation could materially adversely affect our financial position, operating results or cash flows.
ESG Risks
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the U.S. and the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy. For example, the SEC has proposed a mandatory climate change reporting framework that, if implemented, is likely to materially increase the amount of time, monitoring and reporting costs related to these matters. In 2022, the current U.S. administration also announced initiatives targeting the reduction of methane emissions, including a focus on the energy sector, updates to the U.S. Methane Emissions Reduction Action Plan, and proposed updates to EPA standards to cut methane and air pollutants from the oil and natural gas industry. Global efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels, including plans developed in connection with the Paris climate conference in December 2015, the Katowice climate conference in December 2018 and the UN Climate Change Conferences in 2021 and 2022, and initiatives such as the EU Corporate Sustainability Reporting Directive.
Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Additionally, numerous large cities globally and several countries have adopted programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation. Such policies or other laws, regulations, treaties and international agreements related to greenhouse gases and climate change may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons, limit drilling in the offshore oil and natural gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which could materially adversely affect our financial position, operating results or cash flows.
In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be materially adversely affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our drilling rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures
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on our company’s financial performance is highly uncertain because we are unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes.
Consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition, may lead to reduced demand for our services.
The increasing penetration of renewable energy into the energy supply mix, the increased production of electric-powered vehicles and improvements in energy storage, as well as changes in consumer preferences, including increased consumer demand for alternative fuels, energy sources and electric-powered vehicles may materially adversely affect the demand for oil and natural gas and our drilling services. This evolving transition of the global energy system from fossil-based systems of energy production and consumption to more renewable energy sources, commonly referred to as the energy transition, could have a material adverse impact on our results of operations, financial position and cash flows. As a result of changes in consumer preferences and uncertainty regarding the pace of the energy transition and expected impacts on oil and natural gas demand, some of our customers are transitioning their businesses to renewable energy projects and away from oil and natural gas exploration and production, which may result in reduced capital spending by such customers on oil and natural gas projects and in turn reduced demand for our services.
Increased scrutiny from stakeholders and others regarding climate change, as well as our ESG practices, initiatives and reporting responsibilities, could result in additional costs or risks.
In recent years the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, has promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves. Such initiatives aimed at limiting climate change and decarbonization could ultimately interfere with our business activities and operations and our access to capital.
In addition to such initiatives, ESG matters more generally have been the subject of increased focus by investors, customers, investment funds and other market and industry participants, as well as certain regulators, including in the U.S. and the EU. We publish an annual Sustainability Report, which includes disclosure of our ESG practices, aspirations and goals. Our disclosures on these matters rely on management's expectations as of the date the statements are first made, as well as standards for measuring progress that are still in development. These expectations and standards may continue to evolve. Even so, our failure or inability to meet these goals or evolving stakeholder expectations for ESG practices and reporting and even the perception of such failure or inability may potentially harm our reputation and impact employee retention, customer relationships and access to capital, among other matters. For example, certain market participants use third-party benchmarks or scores to measure a company’s ESG practices in making investment decisions and customers and suppliers may evaluate our ESG practices or require that we adopt certain ESG policies as a condition of awarding contracts. By electing to set and share publicly our corporate ESG standards, our business may also face increased scrutiny related to ESG activities. As ESG best-practices and reporting standards continue to develop, we may incur increased costs related to ESG monitoring and reporting and complying with ESG initiatives. In addition, it may be difficult or expensive for us to comply with any ESG-linked contracting policies adopted by customers and suppliers, particularly given the complexity of our supply chain and our reliance on third-party manufacturers. As described in Part I, Item 1. "Business - Sustainability," we have increased our focus on sustainability-related matters. Actions we may take to achieve our sustainability initiatives, including the development and implementation of new emissions-reduction technology, may require increased expenditures, which may materially adversely affect our financial position, operating results or cash flows.
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Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
Contract Drilling Fleet
The following table provides certain information about the rigs in our drilling fleet as of February 21, 2023:
Rig Name | Rig Type | Year Built/ Rebuilt | Design | Maximum Water Depth/ Drilling Depth | Location | Status | ||||||||||||||||||||||||||
| Floaters | ||||||||||||||||||||||||||||||||
| VALARIS DS-4 | Drillship | 2010 | Dynamically Positioned | 12,000'/40,000' | Brazil | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-7 | Drillship | 2013 | Dynamically Positioned | 10,000'/40,000' | Spain | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS DS-8 | Drillship | 2015 | Dynamically Positioned | 12,000'/40,000' | Spain | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS DS-9 | Drillship | 2015 | Dynamically Positioned | 12,000'/40,000' | Angola | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-10 | Drillship | 2015 | Dynamically Positioned | 12,000'/40,000' | Nigeria | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-11 | Drillship | 2013 | Dynamically Positioned | 12,000'/40,000' | Spain | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS DS-12 | Drillship | 2013 | Dynamically Positioned | 12,000'/40,000' | Angola | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-13 | Drillship | Under construction(2) | Dynamically Positioned | 12,000'/40,000' | South Korea | Option(2) | ||||||||||||||||||||||||||
| VALARIS DS-14 | Drillship | Under construction(2) | Dynamically Positioned | 12,000'/40,000' | South Korea | Option(2) | ||||||||||||||||||||||||||
| VALARIS DS-15 | Drillship | 2014 | Dynamically Positioned | 12,000'/40,000' | Brazil | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-16 | Drillship | 2014 | Dynamically Positioned | 12,000'/40,000' | Gulf of Mexico | Under contract | ||||||||||||||||||||||||||
| VALARIS DS-17 | Drillship | 2014 | Dynamically Positioned | 12,000'/40,000' | Spain | Under reactivation(3) | ||||||||||||||||||||||||||
| VALARIS DS-18 | Drillship | 2015 | Dynamically Positioned | 12,000'/40,000' | Gulf of Mexico | Under contract | ||||||||||||||||||||||||||
| VALARIS DPS-1 | Semisubmersible | 2012 | Dynamically Positioned | 10,000'/35,000' | Australia | Under contract | ||||||||||||||||||||||||||
| VALARIS DPS-3 | Semisubmersible | 2010 | Dynamically Positioned | 8,500'/37,500' | Gulf of Mexico | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS DPS-5 | Semisubmersible | 2012 | Dynamically Positioned | 8,500'/35,000' | Mexico | Under contract | ||||||||||||||||||||||||||
| VALARIS DPS-6 | Semisubmersible | 2012 | Dynamically Positioned | 8,500'/35,000' | Gulf of Mexico | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS MS-1 | Semisubmersible | 2011 | F&G ExD Millennium | 8,200'/40,000 | Australia | Under contract | ||||||||||||||||||||||||||
| Jackups | ||||||||||||||||||||||||||||||||
| VALARIS 54 | Jackup | 1982/2004 | F&G L-780 MOD II-C | 300'/25,000' | Saudi Arabia | Under contract | ||||||||||||||||||||||||||
| VALARIS 72 | Jackup | 1981/2011 | Hitachi K1025N | 225'/25,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 75 | Jackup | 1999 | MLT Super 116-C | 400'/30,000' | Gulf of Mexico | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 76 | Jackup | 2000 | MLT Super 116-C | 350'/30,000' | Saudi Arabia | Under contract | ||||||||||||||||||||||||||
| VALARIS 92 | Jackup | 1982/2003 | MLT 116-C | 210'/25,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 102 | Jackup | 2002 | KFELS MOD V-A | 400'/30,000' | Gulf of Mexico | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 104 | Jackup | 2002/2011 | KFELS MOD V-B | 400'/30,000' | UAE | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 106 | Jackup | 2005 | KFELS MOD V-B | 400'/30,000' | Indonesia | Under contract | ||||||||||||||||||||||||||
| VALARIS 107 | Jackup | 2006 | KFELS MOD V-B | 400'/30,000' | Australia | Under contract | ||||||||||||||||||||||||||
| VALARIS 108 | Jackup | 2007/2009 | KFELS MOD V-B | 400'/30,000' | Saudi Arabia | Under contract | ||||||||||||||||||||||||||
| VALARIS 109 | Jackup | 2008 | KFELS MOD V-Super B | 350'/35,000' | Namibia | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 110 | Jackup | 2015 | KFELS MOD V-B | 400'/35,000' | Qatar | Under contract | ||||||||||||||||||||||||||
| VALARIS 111 | Jackup | 2003 | KFELS MOD V Enhanced B-Class | 400'/36,000' | Croatia | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 115 | Jackup | 2013 | Baker Marine Pacific Class 400 | 400'/30,000' | Brunei | Under contract | ||||||||||||||||||||||||||
| VALARIS 116 | Jackup | 2008/2018 | LT 240- C | 375'/35,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 117 | Jackup | 2009 | LT 240- C | 350'/35,000' | Mexico | Under contract | ||||||||||||||||||||||||||
| VALARIS 118 | Jackup | 2012 | LT 240- C | 350'/35,000 | Trinidad | Under contract | ||||||||||||||||||||||||||
| VALARIS 120 | Jackup | 2013 | KFELS Super A | 400'/40,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 121 | Jackup | 2013 | KFELS Super A | 400'/40,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 122 | Jackup | 2013 | KFELS Super A | 400'/40,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
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| Rig Name | Rig Type | Year Built/ Rebuilt | Design | Maximum Water Depth/ Drilling Depth | Location | Status | ||||||||||||||||||||||||||
| Jackups (Continued) | ||||||||||||||||||||||||||||||||
| VALARIS 123 | Jackup | 2016 | KFELS Super A | 400'/40,000' | Netherlands | Under contract | ||||||||||||||||||||||||||
| VALARIS 140 | Jackup | 2016 | LT Super 116E | 340'/30,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 141 | Jackup | 2016 | LT Super 116E | 340'/30,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 143 | Jackup | 2010/2018 | LT EXL Super 116-E | 350'/35,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 144 | Jackup | 2010 | LT Super 116-E | 350'/35,000' | Gulf of Mexico | Under contract | ||||||||||||||||||||||||||
| VALARIS 145 | Jackup | 2010 | LT Super 116-E | 350'/35,000' | Gulf of Mexico | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS 146 | Jackup | 2011/2018 | LT EXL Super 116-E | 320'/35,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 147 | Jackup | 2012/2019 | LT Super 116-E | 350'/30,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 148 | Jackup | 2013/2019 | LT Super 116-E | 350'/30,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS 247 | Jackup | 1998 | LT Super Gorilla | 400'/35,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 248 | Jackup | 2001/2014 | LT Super Gorilla | 400'/35,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
| VALARIS 249 | Jackup | 2001 | LT Super Gorilla | 400'/35,000' | New Zealand | Under contract | ||||||||||||||||||||||||||
| VALARIS 250 | Jackup | 2003 | LT Super Gorilla XL | 550'/35,000' | Saudi Arabia | Leased to ARO drilling | ||||||||||||||||||||||||||
| VALARIS Viking | Jackup | 2011 | KEFLS N Class | 435'/35,000' | United Kingdom | Preservation stacked(1) | ||||||||||||||||||||||||||
| VALARIS Stavanger | Jackup | 2011 | KEFLS N Class | 400'/35,000' | United Kingdom | Available | ||||||||||||||||||||||||||
| VALARIS Norway | Jackup | 2011 | KEFLS N Class | 400'/35,000' | United Kingdom | Under contract | ||||||||||||||||||||||||||
(1)Prior to stacking, upfront steps are taken to preserve the rig. This may include a quayside power source to dehumidify key equipment and/or provide electric current to the hull to prevent corrosion. Also, certain equipment may be removed from the rig for storage in a temperature-controlled environment. While stacked, large equipment that remains on the rig is periodically inspected and maintained by Valaris personnel. These steps are designed to reduce time and lower cost to reactivate the rig when market conditions improve.
(2)We have construction agreements with a shipyard that provide for, among other things, an option construct whereby the Company has the right, but not the obligation, to take delivery of either or both VALARIS DS-13 AND VALARIS DS-14 rigs which were recently constructed, on or before December 31, 2023. Under the amended agreements, the purchase prices for the rigs are estimated to be $119.1 million for the VALARIS DS-13 and $218.3 million for the VALARIS DS-14, assuming a December 31, 2023 delivery date. Delivery can be requested any time prior to December 31, 2023 with a downward purchase price adjustment based on predetermined terms. If the Company elects not to purchase the rigs, the Company has no further obligations to the shipyard.
(3)Rig being reactivated for a firm contract.
The equipment on our drilling rigs includes engines, draw works, derricks, pumps to circulate drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and geological conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.
Floater rigs consist of drillships and semisubmersibles. Drillships are purpose-built maritime vessels outfitted with drilling apparatus. Drillships are self-propelled and can be positioned over a drill site through the use of computer-controlled propellers or "thruster" dynamic positioning systems. Our drillships are capable of drilling in water depths of up to 12,000 feet and are suitable for deepwater drilling in remote locations because of their
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superior mobility and large load-carrying capacity. Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.
Semisubmersibles are drilling rigs with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersibles are held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains or dynamically positioned by computer-controlled propellers or "thrusters" similar to that used by our drillships. Moored semisubmersibles are most commonly used for drilling in water depths of 4,499 feet or less. However, VALARIS MS-1, which is a moored semisubmersible, is capable of deepwater drilling in water depths greater than 5,000 feet. Dynamically positioned semisubmersibles generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling. Further, we have two hybrid semisubmersibles, VALARIS DPS-3 and VALARIS DPS-5, which leverage both moored and dynamically positioned configurations. This hybrid design provides multi-faceted drilling solutions to customers with both shallow water and deepwater requirements.
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackups are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackups provide a more stable drilling platform with above water well-control equipment. Our jackups are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safer drilling of both exploratory and development wells. The jackup hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.
We own all rigs in our fleet and we manage the drilling operations for two platform rigs owned by a third-party.
We lease office space in the United States (Houston and Louisiana), United Kingdom (London and Aberdeen), Australia, Indonesia, Mexico, Brazil, Nigeria, Netherlands, United Arab Emirates (Dubai and Abu Dhabi), Saudi Arabia, Thailand, Norway, New Zealand and Trinidad. We own offices and other facilities in United States (Louisiana), Angola and Brazil.
Item 3. Legal Proceedings
Environmental Matters
We are currently subject to pending notices of assessment relating to spills of drilling fluids, oil, brine, chemicals, grease or fuel from drilling rigs operating offshore Brazil from 2008 to 2019, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines. We have contested these notices and appealed certain adverse decisions and are awaiting decisions in these cases. Although we do not expect final disposition of these assessments to have a material adverse effect on our financial position, operating results and cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $0.5 million liability related to these matters was included in Accrued liabilities and other on our Consolidated Balance Sheet as of December 31, 2022 (Successor) included in "Item 8. Financial Statements."
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
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Item 4. Mine Safety Disclosures
Not applicable.
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PART II
| Item 5. | Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities | ||||
Market Information
Predecessor
As a result of the Chapter 11 Cases, the Class A ordinary shares of Legacy Valaris were delisted from the New York Stock Exchange ("NYSE") effective September 14, 2020. On the Effective Date, the Class A ordinary shares were cancelled.
Successor
On April 30, 2021, pursuant to the Plan, the Company issued an aggregate of approximately 75.0 million Common Shares and 5.6 million Warrants and has listed the Common Shares and the Warrants on the NYSE under the symbols “VAL” and “VAL WS”, respectively.
Many of our shareholders hold shares electronically, all of which are owned by a nominee of the Depository Trust Company. We had 102 shareholders of record on February 1, 2023.
Dividends
For the Successor, we have not paid or declared any dividends on our Common Shares. Our Indenture includes provisions that limit our ability to pay dividends. The Predecessor had not paid or declared dividends since 2019.
Bermuda Tax
We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermudian dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermudian dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our Common Shares.
At the present time, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our shares. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda.
Equity Compensation Plans
For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."
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Issuer Repurchases of Equity Securities
In September 2022, our board of directors authorized a share repurchase program under which we may purchase up to $100 million of our outstanding Common Shares. The share repurchase program does not have a fixed expiration, and may be modified, suspended or discontinued at any time. As of December 31, 2022 (Successor), there have been no share repurchases under this repurchase program.
Cumulative Total Shareholder Return
The chart below presents a comparison of the cumulative total shareholder return, assuming $100 invested on May 3, 2021 (first trading date after our emergence from the Chapter 11 Cases) for Valaris Limited, the Standard & Poor's MidCap 400 Index and Dow Jones US Select Oil Equipment & Services Index.
COMPARISON OF CUMULATIVE TOTAL RETURN(1)
Among Valaris Limited, the S&P MidCap 400 Index and Dow Jones US Select Oil Equipment & Services Index
| May 3, 2021 | December 31, 2021 | December 31, 2022 | |||||||||||||||
| Valaris Limited | 100.0 | 151.9 | 285.3 | ||||||||||||||
| S&P MidCap 400 | 100.0 | 104.6 | 91.0 | ||||||||||||||
| Dow Jones US Select Oil Equipment & Services Index | 100.0 | 96.5 | 160.7 | ||||||||||||||
(1) Total return assuming reinvestment of dividends. Assumes $100 invested on May 3, 2021, which represents the first trading date after our emergence from the Chapter 11 Cases.
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Item 6. Reserved
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 year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and for the four months ended April 30, 2021 (Predecessor). For a similar discussion, including comparisons for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), 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, 2021, filed with the SEC on February 22, 2022.
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. We currently own 52 rigs, including 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 36 jackup rigs and a 50% equity interest in ARO, our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional seven rigs. We also have options to purchase two recently constructed drillships on or before December 31, 2023.
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 current operations spanning six continents. The markets in which we operate include the Gulf of Mexico, South America, the North Sea, 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.
Chapter 11 Proceedings, Emergence from Chapter 11 and Fresh Start Accounting
On the Petition Date, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court.
In connection with the Chapter 11 Cases and the plan of reorganization, on and prior to the Effective Date, Legacy Valaris effectuated certain restructuring transactions, pursuant to which Valaris was formed and, through a series of transactions, Legacy Valaris transferred to a subsidiary of Valaris substantially all of the subsidiaries, and other assets, of Legacy Valaris.
On the Effective Date, we successfully completed our financial restructuring and together with the Debtors emerged from the Chapter 11 Cases. Upon emergence from the Chapter 11 Cases, we eliminated $7.1 billion of debt and obtained a $520 million capital injection by issuing the First Lien Notes. See “Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional
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information on the First Lien Notes. On the Effective Date, the Legacy Valaris Class A ordinary shares were cancelled and the Common Shares were issued. Also, former holders of Legacy Valaris' equity were issued Warrants to purchase Common Shares. See “Note 10 - Shareholders' Equity" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the issuance of the Common Shares and Warrants.
References to the financial position and results of operations of the "Successor" or "Successor Company" relate to the financial position and results of operations of the Company after the Effective Date. References to the financial position and results of operations of the "Predecessor" or "Predecessor Company" refer to the financial position and results of operations of Legacy Valaris on and prior to the Effective Date. References to the “Company,” “we,” “us” or “our” in this Annual Report are to Valaris Limited, together with its consolidated subsidiaries, when referring to periods following the Effective Date, and to Legacy Valaris, together with its consolidated subsidiaries, when referring to periods prior to and including the Effective Date.
Upon emergence from the Chapter 11 Cases, we qualified for and adopted fresh start accounting. The application of fresh start accounting resulted in a new basis of accounting, and the Company became a new entity for financial reporting purposes. Accordingly, our financial statements and notes after the Effective Date are not comparable to our financial statements and notes on and prior to that date.
See “Note 2 – Chapter 11 Proceedings” and "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional details regarding the bankruptcy, our emergence and fresh start accounting.
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.
Over the last several years, oil price volatility, resulting from the global COVID-19 pandemic, production disputes among major oil producing countries and various other factors, significantly impacted our business. In 2020, the combined effects of the COVID-19 pandemic, the significant decline in the demand for oil and the substantial surplus in the supply of oil resulted in significantly reduced demand and day rates for offshore drilling services provided by the Company and increased uncertainty regarding long-term market conditions. These events had a significant adverse impact on our liquidity position and financial runway and led to the filing of the Chapter 11 Cases.
During 2021 and 2022, oil prices increased due to, among other factors, rebounding demand for hydrocarbons, a measured approach to production increases by OPEC+ members, reduction in supply due to Russia’s invasion of Ukraine and the subsequent sanctions placed on Russia, and a focus on cash flow and returns by major exploration and production companies. The more constructive oil price environment has led to an improvement in contracting and tendering activity.
We are experiencing the impacts of global inflation, both in increased personnel costs as well as in the prices of goods and services required to operate our rigs or execute capital projects. While we are currently unable to estimate the ultimate impact of rising prices, we do expect that our costs will continue to rise in the near term and will impact our profitability. 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. See "Item 1A. Risk Factors - Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability."
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The outlook for the offshore drilling industry has improved since the beginning of 2021, as evidenced by increasing global utilization and day rates for offshore drilling rigs, most notably for drillships. However, the combination of global inflation and a tightening of monetary policy has led to increasing concerns of a global economic recession that may have a negative impact on demand for hydrocarbons. As a result, there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for, and profitability of, offshore drilling services.
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 rates, which are subject to adjustment under the terms of the shareholder agreement governing the joint venture.
ARO backlog 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 the equity in earnings of ARO in our Consolidated Statement 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 5 - 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 ARO's contract backlog of business as of February 21, 2023 and 2022 (in millions):
| February 21, 2023 | February 21, 2022 | ||||||||||
Floaters (1) | $ | 1,376.9 | $ | 1,665.3 | |||||||
| Jackups | 742.3 | 643.0 | |||||||||
Other(2) | 344.0 | 135.6 | |||||||||
| Total | $ | 2,463.2 | $ | 2,443.9 | |||||||
| ARO | $ | 1,731.8 | $ | 1,501.1 | |||||||
(1)Our backlog as of February 21, 2022 included approximately $428 million attributable to a contract awarded to VALARIS DS-11 for an eight-well deepwater project in the U.S. Gulf of Mexico that was expected to commence in mid-2024. In June 2022, the customer terminated the contract. As a result of the contract termination, we received an early termination fee of $51.0 million which is included in revenues on our Consolidated Statements of Operations for the year ended December 31, 2022 (Successor). As of the date of the termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract. Costs incurred for capital upgrades specific to the customer requirements were considered to be impaired and as such, we recorded a pre-tax, non-cash loss on impairment in the second quarter of 2022 of $34.5 million. Additional costs were recorded for penalties and other costs incurred upon cancellation of equipment ordered. See "Note 4 - Revenue from Contracts with Customers" and "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
(2)Other includes the bareboat charter backlog for the jackup rigs leased to ARO to fulfill contracts between ARO and Saudi Aramco in addition to backlog for our managed rig services. Substantially all the operating costs for jackups leased to ARO through the bareboat charter agreements will be borne by ARO.
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The increase in our backlog of $19.3 million is primarily due to recent contract awards and contract extensions, partially offset by the termination of the VALARIS DS-11 contract and revenues realized. As revenues are realized and if we experience customer contract cancellations, we may experience declines in backlog, which would result in a decline in revenues and operating cash flows.
The increase in ARO's backlog of $230.7 million is primarily due to contract awards and extensions, including contract awards for VALARIS 76 and 108, which are expected to be leased to ARO following completion of their existing contracts, partially offset by revenues realized.
The following table summarizes our and ARO's contract backlog of business as of February 21, 2023 and the periods in which revenues are expected to be realized (in millions):
| 2023 | 2024 | 2025 and beyond | Total | ||||||||||||||||||||
| Floaters | $ | 753.6 | $ | 562.2 | $ | 61.1 | $ | 1,376.9 | |||||||||||||||
| Jackups | 428.0 | 195.2 | 119.1 | 742.3 | |||||||||||||||||||
| Other | 141.9 | 112.8 | 89.3 | 344.0 | |||||||||||||||||||
| Total | $ | 1,323.5 | $ | 870.2 | $ | 269.5 | $ | 2,463.2 | |||||||||||||||
| ARO | $ | 470.5 | $ | 598.8 | $ | 662.5 | $ | 1,731.8 | |||||||||||||||
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
Starting in 2021, the more constructive oil price environment has led to an improvement in contracting and tendering activity for floaters. The number of contracted benign environment floaters has increased to 115 from a low of 101 in early 2021, contributing to a 10% increase in utilization, from 73% to 83%, for the active fleet over the same period. This increase in activity is particularly evident for drillships. Utilization for the active drillship fleet has been sustained at above 85% for more than twelve months, resulting in a meaningful improvement in day rates for this class of assets. In 2022, we completed the reactivation of three drillships and one semisubmersible which have commenced long-term contracts, and we were awarded an additional long-term contract for one of our stacked drillships that is expected to commence in mid-2023.
Our backlog for our floater segment was $1.4 billion and $1.7 billion as of February 21, 2023 and 2022, respectively. The decrease in our backlog was due to the termination of the VALARIS DS-11 contract, which represented approximately $428 million of backlog, and revenues realized, partially offset by contract awards and contract extensions.
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Utilization for our floaters was 45% during the year ended December 31, 2022, compared to 29% during the year ended December 31, 2021. Average day rates were approximately $213,000 during the year ended December 31, 2022, compared to $193,000 during the year ended December 31, 2021. The increase in average day rate and utilization is primarily due to the four reactivated floaters commencing contracts during 2022.
As of December 31, 2022, the benign environment floater supply declined by 43% to 159 from a peak of 281 in late 2014. Globally, there were 17 newbuild drillships and benign environment semisubmersible rigs reported to be under construction that could increase global supply, of which 13 were scheduled to be delivered before the end of 2023. Most newbuild floaters were uncontracted. Further, with regard to supply, there were 28 benign environment floaters that are either older than 20 years of age and currently idle or have been stacked for more than three years. There were two additional benign environment floaters older than 20 years that have contracts expiring in six months without follow-on work. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify or reactivate some of these aging rigs may prove cost prohibitive. Drilling contractors may elect to scrap or cold stack a portion of these rigs.
A sustained constructive oil price environment and continued demand for offshore projects or further rationalization of drilling rig supply are necessary to maintain current floater utilization and day rates.
Jackups
Contracting and tendering activity for jackups began to improve during 2021 as a result of the more constructive oil price environment. Further, we have seen a notable increase in jackup activity in 2022, primarily driven by demand from the Middle East. The number of contracted jackups has increased to 394 from a low of 341 in early 2021, contributing to a 13% increase in utilization, from 78% to 91%, for the active fleet over the same period.
Our backlog for our jackup segment was $742.3 million and $643.0 million as of February 21, 2023 and 2022, respectively. The increase in our backlog was due to contract awards and contract extensions, partially offset by revenues realized.
Utilization for our jackups was 66% during the year ended December 31, 2022, compared to 54% during the year ended December 31, 2021. The increase in utilization is primarily due to the sale of stacked jackups in 2022 and late 2021. Average day rates were approximately $94,000 during the year ended December 31, 2022, compared to approximately $95,000 during the year ended December 31, 2021.
As of December 31, 2022, jackup supply declined by 9% to 493 from a peak of 542 in early 2015. Globally, there were 20 newbuild jackup rigs reported to be under construction that could increase global supply, of which 15 were scheduled to be delivered before the end of 2023. Most newbuild jackups were uncontracted. Further, with regard to supply, there were 79 jackups that are either older than 30 years and currently idle or have been stacked for more than three years. There were a further 17 jackups that are 30 years or older and have contracts expiring within the next six months without follow-on work. Expenditures required to re-certify or reactivate some of these rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold stack these rigs.
A sustained constructive oil price environment and continued demand for offshore projects or further rationalization of drilling rig supply are necessary to maintain jackup utilization and day rates.
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RESULTS OF OPERATIONS
The following table summarizes our Consolidated Results of Operations for the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and the combined Successor and Predecessor results for the year ended December 31, 2021 (Non-GAAP) (in millions):
| Successor | Predecessor | Combined (Non-GAAP)(1) | ||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2021 | |||||||||||||||||||||||
| Revenues | $ | 1,602.5 | $ | 835.0 | $ | 397.4 | $ | 1,232.4 | ||||||||||||||||||
| Operating expenses | ||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 1,383.2 | 724.1 | 343.8 | 1,067.9 | ||||||||||||||||||||||
| Loss on impairment | 34.5 | — | 756.5 | 756.5 | ||||||||||||||||||||||
| Depreciation | 91.2 | 66.1 | 159.6 | 225.7 | ||||||||||||||||||||||
| General and administrative | 80.9 | 58.2 | 30.7 | 88.9 | ||||||||||||||||||||||
| Total operating expenses | 1,589.8 | 848.4 | 1,290.6 | 2,139.0 | ||||||||||||||||||||||
| Equity in earnings of ARO | 24.5 | 6.1 | 3.1 | 9.2 | ||||||||||||||||||||||
| Operating income (loss) | 37.2 | (7.3) | (890.1) | (897.4) | ||||||||||||||||||||||
| Other income (expense), net | 187.7 | 20.1 | (3,557.5) | (3,537.4) | ||||||||||||||||||||||
| Provision for income taxes | 43.1 | 36.4 | 16.2 | 52.6 | ||||||||||||||||||||||
| Net income (loss) | 181.8 | (23.6) | (4,463.8) | (4,487.4) | ||||||||||||||||||||||
| Net income attributable to noncontrolling interests | (5.3) | (3.8) | (3.2) | (7.0) | ||||||||||||||||||||||
| Net income (loss) attributable to Valaris | $ | 176.5 | $ | (27.4) | $ | (4,467.0) | $ | (4,494.4) | ||||||||||||||||||
(1) We believe that the discussion of our results of operations for the eight months ended December 31, 2021 (Successor) combined with the four months ended April 30, 2021 (Predecessor) provides a more meaningful comparison to the year ended December 31, 2022 (Successor) and is more useful in understanding operational trends. These combined results do not comply with accounting principles generally accepted in the United States of America ("GAAP") and have not been prepared as pro forma results under applicable SEC rules.
Overview
Revenues increased $370.1 million, or 30.0%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to $227.8 million resulting from more operating days in 2022, a $51.0 million fee recognized for the early termination of the VALARIS DS-11 contract in 2022, a $47.2 million increase in amortization of deferred mobilization and capital upgrade revenue, $19.3 million from higher customer reimbursable revenue, and $18.2 million from higher average day rates on certain rigs.
Contract drilling expense increased $315.3 million, or 29.5%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to a $213.2 million increase attributable to rigs that have returned to work upon completion of reactivation projects or after being idle in the prior year period, a $36.8 million increase in the costs for certain claims, a $32.4 million increase in reactivation costs, and a $20.5 million increase in reimbursable costs.
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During 2022 (Successor), we recorded non-cash losses on impairment totaling $34.5 million with respect to customer-specific capital upgrades for VALARIS DS-11 made pursuant to the terms of the drilling contract that was terminated during the second quarter of 2022. During the four months ended April 30, 2021 (Predecessor), we recorded non-cash losses on impairment totaling $756.5 million, with respect to certain assets in our fleet. See "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Depreciation expense declined $134.5 million, or 59.6%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.
General and administrative expenses declined by $8.0 million or 9.0%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to a change in incentive compensation structure following the Effective Date.
Other income (expense), net, changed from an expense of $3.5 billion in the combined Successor and Predecessor prior year period to income of $187.7 million for the year ended December 31, 2022 (Successor). In the prior year, we recorded $3.6 billion of reorganization costs incurred directly related to the Chapter 11 Cases. In 2022, we recognized a pre-tax gain on sale of property of $141.2 million primarily from the sale of VALARIS 113, VALARIS 114, VALARIS 36 and VALARIS 67 as well as additional proceeds received in 2022 from two rigs sold in prior years as a result of post-sale conditions of those sale agreements. We also recognized non-cash interest income of $14.8 million for the adjustment to the discount resulting from the partial early repayment on our Notes Receivable from ARO and $8.9 million of interest income in 2022 on investments during the period.
Rig Counts, Utilization and Average Day Rates
The following table summarizes our and ARO's offshore drilling rigs as of December 31, 2022 and 2021:
| 2022 | 2021 | ||||||||||
| Floaters | 16 | 16 | |||||||||
Jackups(1) | 28 | 33 | |||||||||
Other(2) | 8 | 7 | |||||||||
| Total Valaris | 52 | 56 | |||||||||
ARO(3) | 7 | 7 | |||||||||
(1)During the first quarter of 2022, we sold VALARIS 67 and leased VALARIS 140 to ARO. During the second quarter of 2022, we sold VALARIS 113 and VALARIS 114. During the third quarter of 2022, we leased VALARIS 141 to ARO.
(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 contracts with Saudi Aramco. During the first quarter of 2022, VALARIS 140 was leased to ARO. During the second quarter of 2022, we sold VALARIS 36, which was previously leased to ARO. During the third quarter of 2022, VALARIS 141 was leased to ARO.
(3)This represents the seven jackup rigs owned by ARO which are operating under long-term contracts with Saudi Aramco.
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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We are a party to contracts whereby we have the option to take delivery of two recently constructed drillships that are not included in the table above. See "Note 14 - Commitments and Contingencies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Additionally, ARO has ordered two jackups which are under construction in the Middle East that are not included in the table above.
The following table summarizes our and ARO's rig utilization and average day rates by reportable segment:
| 2022 | 2021 | ||||||||||
Rig Utilization(1) | |||||||||||
| Floaters | 45% | 29% | |||||||||
| Jackups | 66% | 54% | |||||||||
Other(2) | 100% | 100% | |||||||||
| Total Valaris | 66% | 55% | |||||||||
| ARO | 92% | 87% | |||||||||
Average Day Rates(3) | |||||||||||
| Floaters | $ | 212,869 | $ | 192,984 | |||||||
| Jackups | 93,795 | 95,304 | |||||||||
Other(2) | 37,952 | 31,301 | |||||||||
| Total Valaris | $ | 102,308 | $ | 88,847 | |||||||
| ARO | $ | 93,690 | $ | 73,799 | |||||||
(1)Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract 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 days under contract.
(2)Includes our two management services contracts and our rigs leased to ARO under bareboat charter contracts.
(3)Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues, lump-sum revenues, revenues earned during suspension periods and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain suspension periods, mobilizations and demobilizations.
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.
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".
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The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO.
Segment information for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the combined Successor and Predecessor results for the year ended December 31, 2021 (Non-GAAP) is as follows (in millions).
Year Ended December 31, 2022 (Successor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 700.5 | $ | 744.2 | $ | 459.5 | $ | 157.8 | $ | (459.5) | $ | 1,602.5 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 646.0 | 538.9 | 341.8 | 76.4 | (219.9) | 1,383.2 | |||||||||||||||||||||||||||||
| Loss on impairment | 34.5 | — | — | — | — | 34.5 | |||||||||||||||||||||||||||||
| Depreciation | 50.0 | 36.1 | 63.4 | 4.6 | (62.9) | 91.2 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 18.7 | — | 62.2 | 80.9 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 24.5 | 24.5 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (30.0) | $ | 169.2 | $ | 35.6 | $ | 76.8 | $ | (214.4) | $ | 37.2 | |||||||||||||||||||||||
Eight Months Ended December 31, 2021 (Successor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 254.5 | $ | 487.1 | $ | 307.1 | $ | 93.4 | $ | (307.1) | $ | 835.0 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 250.7 | 365.2 | 246.2 | 38.9 | (176.9) | 724.1 | |||||||||||||||||||||||||||||
| Depreciation | 31.0 | 32.0 | 44.2 | 2.8 | (43.9) | 66.1 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 13.6 | — | 44.6 | 58.2 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 6.1 | 6.1 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (27.2) | $ | 89.9 | $ | 3.1 | $ | 51.7 | $ | (124.8) | $ | (7.3) | |||||||||||||||||||||||
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Four Months Ended April 30, 2021 (Predecessor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 115.7 | $ | 232.4 | $ | 163.5 | $ | 49.3 | $ | (163.5) | $ | 397.4 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 106.5 | 175.0 | 116.1 | 19.9 | (73.7) | 343.8 | |||||||||||||||||||||||||||||
| Loss on impairment | 756.5 | — | — | — | — | 756.5 | |||||||||||||||||||||||||||||
| Depreciation | 72.1 | 69.7 | 21.0 | 14.8 | (18.0) | 159.6 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 4.2 | — | 26.5 | 30.7 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 3.1 | 3.1 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (819.4) | $ | (12.3) | $ | 22.2 | $ | 14.6 | $ | (95.2) | $ | (890.1) | |||||||||||||||||||||||
Combined Year Ended December 31, 2021 (Non-GAAP)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 370.2 | $ | 719.5 | $ | 470.6 | $ | 142.7 | $ | (470.6) | $ | 1,232.4 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 357.2 | 540.2 | 362.3 | 58.8 | (250.6) | 1,067.9 | |||||||||||||||||||||||||||||
| Loss on impairment | 756.5 | — | — | — | — | 756.5 | |||||||||||||||||||||||||||||
| Depreciation | 103.1 | 101.7 | 65.2 | 17.6 | (61.9) | 225.7 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 17.8 | — | 71.1 | 88.9 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 9.2 | 9.2 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (846.6) | $ | 77.6 | $ | 25.3 | $ | 66.3 | $ | (220.0) | $ | (897.4) | |||||||||||||||||||||||
Floaters
Floater revenue increased $330.3 million, or 89%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to $200.2 million resulting from more operating days in 2022, a $51.0 million fee recognized for the early termination of the VALARIS DS-11 contract in 2022, $29.4 million from increased average day rates on certain rigs, $24.5 million from higher customer reimbursable revenue, and a $20.1 million increase in amortization of deferred mobilization and capital upgrade revenue.
Floater contract drilling expense increased $288.8 million, or 81%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to increases of $134.4 million attributable to rigs that have returned to work upon completion of reactivation projects or after being idle in the prior year period, $82.4 million in reactivation costs, $30.6 million in the costs for certain claims, $24.7 million in reimbursable costs, and $13.1 million in repair cost for certain rigs.
During 2022 (Successor), we recorded non-cash losses on impairment totaling $34.5 million, with respect to customer-specific capital upgrades for VALARIS DS-11 made pursuant to the terms of the drilling contract that was terminated during the second quarter of 2022. During the four months ended April 30, 2021 (Predecessor), we recorded a non-cash loss on impairment totaling $756.5 million with respect to certain assets in our Floater segment.
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See "Note 7 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Floater depreciation expense declined $53.1 million, or 52%, for the year ended December 31, 2022 (Successor), as compared to the combined Successor and Predecessor prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.
Jackups
Jackup revenues increased $24.7 million, or 3%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to increases of $29.8 million in amortization of deferred mobilization and capital upgrade revenue and $27.6 million resulting from more operating days in 2022. These increases were partially offset by a decrease of $25.5 million from average day rates on certain rigs and a decrease of $10.0 million from lower customer reimbursable revenue.
Jackup contract drilling expense remained consistent, declining only $1.3 million, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to a $49.6 million decrease in reactivation costs, a $15.5 million decrease due to rigs which were leased to ARO and a $10.5 million decrease due to rigs which were sold, being offset by a $78.8 million increase in costs attributable to rigs that have returned to work after being idle in the prior year period.
Jackup depreciation expense declined $65.6 million, or 65%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.
ARO
ARO currently owns a fleet of seven jackup rigs, leases another eight jackup rigs from us and has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. While the shipyard contract contemplated delivery of these newbuild rigs in 2022, the delivery of these rigs has been delayed into 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the newbuilds ordered in January 2020 and is actively exploring financing options for the remaining payments due upon delivery. In the event ARO has insufficient cash from operations 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. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered on a proportionate basis.
The joint venture partners agreed in the Shareholder Agreement that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. The initial contracts provided by Saudi Aramco for each the newbuild rigs will be for an eight-year term. The day rate for the initial contracts for each newbuild rig will be determined using a pricing mechanism that targets a six-year payback period for construction costs on an EBITDA basis. The initial eight-year contracts will be followed by a minimum of another eight years of term, re-priced in three-year intervals based on a market pricing mechanism. As of December 31, 2022, we leased eight rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All the jackup rigs leased to ARO are operating under three-year contracts, or related extensions, with Saudi Aramco. All seven ARO-owned jackup rigs are currently operating under long-term contracts with Saudi Aramco. See "Note 5 - 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.
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The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for the seven 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.
Revenue for the year ended December 31, 2022 decreased $11.1 million or 2% as compared to the prior year primarily due to a $51.0 million decrease from three rigs which operated in the prior year period completing their contracts in 2021 or 2022. This decrease was partially offset by a $32.5 million increase from VALARIS 140 and VALARIS 141, which were leased to ARO and commenced drilling operations during 2022, and a $6.7 million increase due to lower temporary suspension or planned maintenance days for certain rigs in 2022 as compared to the prior year period.
Contract drilling expense for the year ended December 31, 2022, decreased $20.5 million or 6% as compared to the prior year primarily due to a decrease in bareboat charter lease expense of $12.9 million, primarily as a result of fewer rigs leased from us during 2022, a $5.0 million decrease in personnel cost, and a $4.4 million decrease in repairs and maintenance cost for certain rigs.
Other
Other revenues increased $15.1 million, or 11%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to an increase of $14.3 million from average day rates on certain rigs.
Other contract drilling expenses increased $17.6 million, or 30%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to a $8.6 million increase in costs for certain claims, a $4.9 million increase in personnel costs and a $4.4 million increase in reimbursable costs.
Depreciation expense declined $13.0 million, or 74%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to the reduction in the values of property and equipment from the application of fresh start accounting on the Effective Date.
Other Income (Expense), Net
The following table summarizes other income (expense), net, (in millions):
| Successor | Predecessor | Combined (Non-GAAP) | ||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2021 | |||||||||||||||||||||||
| Net gain on sale of property | $ | 141.2 | $ | 21.2 | $ | 6.0 | $ | 27.2 | ||||||||||||||||||
| Interest income | 65.5 | 28.5 | 3.6 | 32.1 | ||||||||||||||||||||||
| Interest expense, net | (45.3) | (31.0) | (2.4) | (33.4) | ||||||||||||||||||||||
| Net foreign currency exchange gains | 12.2 | 8.1 | 13.4 | 21.5 | ||||||||||||||||||||||
| Reorganization items, net | (2.4) | (15.5) | (3,584.6) | (3,600.1) | ||||||||||||||||||||||
| Other, net | 16.5 | 8.8 | 6.5 | 15.3 | ||||||||||||||||||||||
| $ | 187.7 | $ | 20.1 | $ | (3,557.5) | $ | (3,537.4) | |||||||||||||||||||
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Net gains on the sale of property of $141.2 million were recognized in 2022 primarily related to the sales of VALARIS 113, VALARIS 114, VALARIS 36 and VALARIS 67 as well as additional proceeds received from two rigs sold in prior years as a result of post-sale conditions of those sale agreements.
Interest income increased by $33.4 million or 104% for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to non-cash interest income of $14.8 million recognized in the third quarter of 2022 for the discount attributable to the partial repayment on our Notes Receivable from ARO and due to incremental amortization as the discount was amortized for eight months in the combined prior year period as opposed to twelve months in 2022. Further, we recognized $8.9 million of interest income in 2022 on investments during the period.
Interest expense, net increased by $11.9 million, or 36%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to our First Lien Notes which were outstanding for eight months in the combined prior year period as compared to twelve months in 2022.
Reorganization items, net of $3.6 billion for the combined Successor and Predecessor prior year period were recognized related to legal and other professional advisory service fees pertaining to the Chapter 11 Cases, contract items related to rejecting certain operating leases and the effects of the emergence from bankruptcy; including the application of fresh start accounting.
Our functional currency is the U.S. dollar, and we predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. However, we have net assets and liabilities denominated in numerous foreign currencies and a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates.
Net foreign currency exchange gains of $12.2 million for the year ended December 31, 2022 (Successor) primarily included gains of $7.2 million, $1.9 million and $1.7 million related to euros, Egyptian pounds and Norwegian kroner, respectively. Net foreign currency exchange gains of $21.5 million for the combined Successor and Predecessor prior year period primarily included $11.7 million and $8.8 million related to Libyan dinar and euros, respectively.
Provision for Income Taxes
Valaris Limited is domiciled and resident 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 as there is not an income tax regime in Bermuda. Legacy Valaris was domiciled and resident in the U.K. The income of our non-U.K. subsidiaries was generally not subject to U.K. 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
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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.
Effective Tax Rate
During the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), we recorded an income tax expense of $43.1 million, $36.4 million and $16.2 million, respectively. Our consolidated effective income tax rates during the same periods were 19.2%, 284.4%, and (0.4)%, respectively.
Our 2022 consolidated effective income tax rate includes $10.3 million associated with the impact of various discrete items, including a $17.2 million income tax benefit associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset primarily by tax expense attributable to income associated with a contract termination.
Our eight months ended December 31, 2021 (Successor) consolidated effective income tax rate includes $14.3 million associated with the impact of various discrete items, including $29.7 million income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $15.4 million of tax benefit related to deferred taxes associated with Switzerland tax reform. Our four months ended April 30, 2021 (Predecessor) consolidated effective income tax rate included $2.2 million associated with the impact of various discrete items, including $21.5 million of income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $19.3 million of tax benefit related to fresh start accounting adjustments.
Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) were 73.6%, 213.9%, and (12.9)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-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.
Divestitures
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 nine jackup rigs during the two-year period ended December 31, 2022.
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 Indenture, 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.
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We sold the following rigs during the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) (in millions):
| Rig | Date of Sale | Segment(1) | Net Proceeds | Net Book Value | Pre-tax Gain | |||||||||||||||||||||||||||
Year Ended December 31, 2022 (Successor) | ||||||||||||||||||||||||||||||||
| VALARIS 36 | May 2022 | Jackups | $ | 8.8 | $ | 0.3 | $ | 8.5 | ||||||||||||||||||||||||
| VALARIS 113 | April 2022 | Jackups | 62.0 | 2.0 | 60.0 | |||||||||||||||||||||||||||
| VALARIS 114 | April 2022 | Jackups | 62.0 | 2.0 | 60.0 | |||||||||||||||||||||||||||
| VALARIS 67 | March 2022 | Jackups | 5.0 | 3.0 | 2.0 | |||||||||||||||||||||||||||
| $ | 137.8 | $ | 7.3 | $ | 130.5 | |||||||||||||||||||||||||||
Eight Months Ended December 31, 2021 (Successor) | ||||||||||||||||||||||||||||||||
| VALARIS 37 | November 2021 | Jackups | $ | 4.2 | $ | 0.3 | $ | 3.9 | ||||||||||||||||||||||||
| VALARIS 22 | October 2021 | Jackups | 4.0 | 0.3 | 3.7 | |||||||||||||||||||||||||||
| VALARIS 142 | October 2021 | Jackups | 15.0 | 2.0 | 13.0 | |||||||||||||||||||||||||||
| VALARIS 100 | August 2021 | Jackups | 1.1 | 1.0 | 0.1 | |||||||||||||||||||||||||||
| $ | 24.3 | $ | 3.6 | $ | 20.7 | |||||||||||||||||||||||||||
| Four Months Ended April 30, 2021 (Predecessor) | ||||||||||||||||||||||||||||||||
| VALARIS 101 | April 2021 | Jackups | $ | 26.4 | $ | 21.1 | $ | 5.3 | ||||||||||||||||||||||||
| $ | 26.4 | $ | 21.1 | $ | 5.3 | |||||||||||||||||||||||||||
(1)Classification denotes the location of the operating results and gain on sale for each rig in our Consolidated Statements of Operations.
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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. 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 contains covenants that limit our ability to incur additional indebtedness.
As of December 31, 2022 and 2021 (Successor), our cash and cash equivalents were $724.1 million and $608.7 million, respectively. We have no debt principal payments due until 2028. See "Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the First Lien Notes.
Cash Flows and Capital Expenditures
Absent periods where we have significant financing or investing transactions or activities, such as debt or equity issuances, 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 or used in operating activities and capital expenditures were as follows (in millions):
| Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | |||||||||||||||||||||
Net cash provided by (used in) operating activities | $ | 127.5 | $ | (26.2) | $ | (39.8) | |||||||||||||||||
| Capital expenditures | $ | (207.0) | $ | (50.2) | $ | (8.7) | |||||||||||||||||
During the year ended December 31, 2022 (Successor), our other primary sources of cash were proceeds of $150.3 million for the disposition of assets and $40.0 million from the partial early repayment of the Notes Receivable from ARO. For the same period, our cash provided by operating activities of $127.5 million related primarily to improving margins and the collection of $54.8 million for certain tax receivables.
In the second quarter of 2022, our customer terminated an eight-well contract for the VALARIS DS-11 and as a result, we recorded an early termination fee of $51.0 million that was collected in July 2022. As of the date of termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract, including $34.5 million of capital costs which were considered to be impaired. Additional costs were recorded for penalties and other costs incurred upon cancellation of equipment ordered.
During the eight months ended December 31, 2021 (Successor), our primary source of cash was proceeds of $25.1 million for the disposition of assets. For the same period, our uses of cash in operating activities of $26.2 million primarily relates to reorganization costs and interest payments on the First Lien Notes. During the four months ended April 30, 2021 (Predecessor), our primary sources of cash were $520.0 million from the issuance of the First Lien Notes and proceeds of $30.1 million for the disposition of assets. For the same period, our uses of cash in operating activities of $39.8 million primarily related to declining margins and reorganization costs.
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We have construction agreements, as amended, with a shipyard that provide for, among other things, an option construct whereby we have the right, but not the obligation, to take delivery on or before December 31, 2023 of either or both VALARIS DS-13 and VALARIS DS-14 rigs, which were recently constructed. Under the amended agreements, the purchase prices for the rigs are estimated to be $119.1 million for VALARIS DS-13 and $218.3 million for VALARIS DS-14, assuming a December 31, 2023 delivery date. Delivery can be requested any time prior to December 31, 2023 with a downward purchase price adjustment based on predetermined terms. If we elect not to purchase the rigs, we have no further obligations to the shipyard.
We continue to take a disciplined approach to reactivations with our stacked rigs, only returning them to the active fleet when there is visibility into work at attractive economics. In most cases, we expect the initial contract to pay for the reactivation costs and that the rig would have solid prospects for longer-term work. Most of the reactivation cost will be 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. We would generally expect to be compensated for any customer-specific enhancements.
Based on our current projections, we expect capital expenditures during 2023 to approximate $260 million to $300 million. This includes approximately $120 million to $130 million for capital maintenance projects and approximately $140 million to $170 million for rig enhancements and upgrades, including approximately $80 million to $90 million for rig reactivation and associated contract-specific capital expenditures. If we exercise our options to take delivery of VALARIS DS-13 for $119.1 million and/or VALARIS DS-14 for $218.3 million on the delivery date of December 31, 2023, our capital expenditures would be higher by the respective purchase prices. Depending on market conditions, contracting activity and future opportunities, we may reactivate additional rigs or make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.
As we reactivated rigs in 2022, spending levels increased beyond the levels we incurred in 2021, with more spending associated with reactivation of our floater fleet relative to our jackup fleet. In 2022, the cost and duration of reactivations increased relative to those in 2021 as a result of the rising costs of labor and materials, the depletion of spares from our initial reactivation projects and as the rigs reactivated had been preservation stacked for longer periods of time. Future reactivations could be subject to further increases in the cost of labor and materials and could take longer due to increased lead times for parts and supplies.
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, 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.
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Financing and Capital Resources
Successor First Lien Notes Indenture
On the Effective Date, in accordance with the plan of reorganization and Backstop Commitment Agreement, dated August 18, 2020 (as amended, the "BCA"), the Company consummated the rights offering of the First Lien Notes and associated Common Shares in an aggregate principal amount of $550.0 million. In accordance with the BCA, certain holders of senior notes claims and certain holders of claims under the Revolving Credit Facility who provided backstop commitments received the backstop premium in an aggregate amount equal to $50.0 million in First Lien Notes and 2.7% of the Common Shares on the Effective Date. The Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date, which was loaned back to the reorganized company upon emergence. Therefore, upon emergence the Debtors received $520.0 million in cash in exchange for a $550.0 million note, which includes the backstop premium. See “Note 2 – Chapter 11 Proceedings” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
The First Lien Notes were issued pursuant to the Indenture among Valaris Limited, certain direct and indirect subsidiaries of Valaris Limited as guarantors, and Wilmington Savings Fund Society, FSB, as collateral agent and trustee (in such capacities, the “Collateral Agent”).
The First Lien Notes are guaranteed, jointly and severally, on a senior basis, by certain of the direct and indirect subsidiaries of the Company. The First Lien Notes and such guarantees are secured by first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by the Company or any guarantor and a first-priority perfected lien on substantially all assets of the Company and each guarantor of the First Lien Notes, in each case subject to certain exceptions and limitations. The following is a brief description of the material provisions of the Indenture and the First Lien Notes.
The First Lien Notes are scheduled to mature on April 30, 2028. Interest on the First Lien Notes accrues, at our option, at a rate of: (1) 8.25% per annum, payable in cash; (2) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (3) 12% per annum, with the entirety of such interest to be paid in kind. Interest is due semi-annually in arrears on May 1 and November 1 of each year and shall be computed on the basis of a 360-day year of twelve 30-day months.
At any time prior to April 30, 2023, the Company may redeem up to 35% of the aggregate principal amount of the First Lien Notes at a redemption price of 104% up to the net cash proceeds received by the Company from equity offerings provided that at least 65% of the aggregate principal amount of the First Lien Notes remains outstanding and provided that the redemption occurs within 120 days after such equity offering of the Company. At any time prior to April 30, 2023 the Company may redeem the First Lien Notes at a redemption price of 104% of the principal amount plus a “make-whole” premium. On or after April 30, 2023, the Company may redeem all or part of the First Lien Notes at fixed redemption prices (which are expressed as percentages of the principal amount), beginning at 104% on April 30, 2023 and declining each 12-month period thereafter to 100% on and after April 30, 2026, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Notwithstanding the foregoing, if a Change of Control (as defined in the Indenture, with certain exclusions as provided therein) occurs, the Company will be required to make an offer to repurchase all or any part of each note holder’s notes at a purchase price equal to 101% of the aggregate principal amount of First Lien Notes repurchased, plus accrued and unpaid interest to, but excluding, the applicable date.
The Indenture contains covenants that limit, among other things, the Company's ability and the ability of the guarantors and other restricted subsidiaries, to: (1) incur, assume or guarantee additional indebtedness; (2) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (3) make investments; (4) repay or redeem junior debt; (5) transfer or sell assets; (6) enter into sale and lease back transactions; (7) create, incur or assume liens; and (8) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions.
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The Indenture also provides for certain customary events of default, including, among other things, nonpayment of principal or interest, breach of covenants, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a collateral document to create an effective security interest in collateral, with a fair market value in excess of a specified threshold, bankruptcy and insolvency events, cross payment default and cross acceleration, which could permit the principal, premium, if any, interest and other monetary obligations on all the then outstanding First Lien Notes to be declared due and payable immediately.
The Company incurred $5.2 million in issuance costs in 2021 associated with the First Lien Notes. Also, in August 2022, the Company completed a consent solicitation pursuant to which the Company amended the Indenture to (1) implement a consolidated net income builder basket for restricted payments, increase the general basket for restricted payments from $100.0 million to $175.0 million and make other incremental changes to the Company’s restricted payments capacity and (2) increase the general basket for investments from the greater of $100.0 million and 4.0% of total assets to the greater of $175.0 million and 6.5% of total assets. The Company incurred $3.9 million of costs in connection with the consent solicitation, comprised of a consent fee paid to consenting holders and professional fees. These costs along with the issuance costs incurred in 2021 are being amortized into interest expense over the expected term of the First Lien Notes using the effective interest method.
Investment in ARO and Notes Receivable from ARO
We consider our investment in ARO to be a significant component of our investment portfolio and an integral part of our long-term capital resources. 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 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 September 2022, the Company received a principal payment of $40.0 million from ARO representing a partial early repayment of the Notes Receivable 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. See "Note 5 - 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.
The following table summarizes the maturity schedule of our Notes Receivable from ARO as of December 31, 2022 (Successor) (in millions):
| Maturity Date | Principal amount | ||||
| October 2027 | $ | 225.0 | |||
| October 2028 | 177.7 | ||||
| Total | $ | 402.7 | |||
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Contractual Obligations
The following table summarizes our significant contractual obligations as of December 31, 2022 (Successor) and the periods in which such obligations are due (in millions):
| Payments due by period | |||||||||||||||||||||||||||||
| 2023 | 2024 and 2025 | 2026 and 2027 | Thereafter | Total | |||||||||||||||||||||||||
| Principal payments on long-term debt | $ | — | $ | — | $ | — | $ | 550.0 | $ | 550.0 | |||||||||||||||||||
Interest payments on long-term debt(1) | 45.4 | 90.7 | 90.7 | 22.7 | 249.5 | ||||||||||||||||||||||||
| Operating leases | 10.7 | 6.2 | 4.8 | 6.1 | 27.8 | ||||||||||||||||||||||||
Total contractual obligations(2) | $ | 56.1 | $ | 96.9 | $ | 95.5 | $ | 578.8 | $ | 827.3 | |||||||||||||||||||
(1)Interest on the First Lien Notes accrues, at our option, at a rate of: (1) 8.25% per annum, payable in cash; (2) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (3) 12% per annum, with the entirety of such interest to be paid in kind. Interest in the table above assumes 8.25% per annum of cash interest payments.
(2)Contractual obligations do not include $275.0 million of unrecognized tax benefits, inclusive of interest and penalties, included on our Consolidated Balance Sheet as of December 31, 2022 (Successor). 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. ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. We expect delivery of the rigs in 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the newbuilds ordered in January 2020 and is actively exploring financing options for remaining payments due upon delivery. In the event ARO has insufficient cash from operations 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. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered on a proportionate basis. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our joint venture.
Other Commitments
We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of December 31, 2022 (Successor), we were contingently liable for an aggregate amount of $141.4 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, 2022 (Successor) , we had collateral deposits in the amount of $20.7 million with respect to these agreements.
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The following table summarizes our other commitments as of December 31, 2022 (in millions):
| Commitment expiration by period | |||||||||||||||||||||||||||||
| 2023 | 2024 and 2025 | 2026 and 2027 | Thereafter | Total | |||||||||||||||||||||||||
| Letters of credit | $ | 116.7 | $ | 14.1 | $ | 10.6 | $ | — | $ | 141.4 | |||||||||||||||||||
Tax Assessments
During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $68.8 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 million payment (approximately $29.0 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have an $17.8 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2022 (Successor). We believe our tax returns are materially correct as filed, and we are vigorously contesting these assessments. Although the outcome of such assessments and related administrative proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows. See "Note 13 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the tax assessments.
Share Repurchase Program
In September 2022, our board of directors authorized a share repurchase program under which we may purchase up to $100.0 million of our outstanding Common Shares. The share repurchase program does not have a fixed expiration, and may be modified, suspended or discontinued at any time. We are under no obligation to purchase any Common Shares under the share repurchase program. Common Shares may be repurchased under the repurchase program in open market purchases, private-negotiated purchases, through block trades, by effecting a tender offer, by way of accelerated share repurchase transactions or other derivative transactions, through the purchase of call options or the sale of put options, or otherwise, or by any combination of the foregoing. The manner, timing, pricing and amount of any repurchases will be subject to our discretion and may be based upon a number of factors, including market conditions, our earnings, capital requirements, financial conditions, available cash resources and competing uses for cash that may arise in the future, debt agreement restrictions other factors. We did not repurchase any Common Shares during the year ended December 31, 2022 under the repurchase program.
Guarantees of Registered Securities
The First Lien Notes issued by Valaris Limited have been fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by certain of the direct and indirect subsidiaries (the “Guarantors”) of Valaris Limited under the Indenture governing the First Lien Notes (the “Guarantees”). The First Lien Notes and Guarantees are secured by liens on the collateral, including, among other things, subject to certain agreed security principles, (1) first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by Valaris Limited or any Guarantor and (2) a first-priority perfected lien on substantially all assets of Valaris Limited and each Guarantor, in each case subject to certain exceptions and limitations (collectively, the “Collateral”). We are providing the following information about the Guarantors and the Collateral in compliance with Rules 13-01 and 13-02 of Regulation S-X.
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First Lien Note Guarantees
The Guarantees are joint and several senior secured obligations of each Guarantor and rank equally in right of payment with existing and future senior indebtedness of such Guarantor and effectively senior to such Guarantor’s existing and future indebtedness (1) that is not secured by a lien on the Collateral securing the First Lien Notes, or (2) that is secured by a lien on the Collateral securing the First Lien Notes ranking junior to the liens securing the First Lien Notes. The Guarantees rank effectively junior to such Guarantor’s existing and future secured indebtedness (1) that is secured by a lien on the Collateral that is senior or prior to the lien securing the First Lien Notes, or (2) that is secured by liens on assets that are not part of the Collateral, to the extent of the value of such assets. The Guarantees rank equally with such Guarantor’s existing and future indebtedness that is secured by first-priority liens on the Collateral and senior in right of payment to any existing and future subordinated indebtedness of such Guarantor. The Guarantees are structurally subordinated to all existing and future indebtedness and other liabilities of any non-Guarantors, including trade payables (other than indebtedness and liabilities owed to such Guarantor).
Under the Indenture, a Guarantor may be automatically and unconditionally released and relieved of its obligations under its guarantee under certain circumstances, including: (1) in connection with any sale, transfer or other disposition (including by merger, consolidation, distribution, dividend or otherwise) of all or substantially all of the assets of such Guarantor to a person that is not the Company or a restricted subsidiary, if such sale, transfer or other disposition is conducted in accordance with the applicable terms of the Indenture, (2) in connection with any sale, transfer or other disposition (including by merger, consolidation, amalgamation, distribution, dividend or otherwise) of all of the capital stock of any Guarantor, if such sale, transfer or other disposition is conducted in accordance with the applicable terms of the Indenture, (3) upon our exercise of legal defeasance, covenant defeasance or discharge under the Indenture, (4) unless an event of default has occurred and is continuing, upon the dissolution or liquidation of a Guarantor in accordance with the Indenture, and (5) if such Guarantor is properly designated as an unrestricted subsidiary, in each case in accordance with the provisions of the Indenture.
We conduct our operations primarily through our subsidiaries. As a result, our ability to pay principal and interest on the First Lien Notes is dependent on the cash flow generated by our subsidiaries and their ability to make such cash available to us by dividend or otherwise. The Guarantors’ earnings will depend on their financial and operating performance, which will be affected by general economic, industry, financial, competitive, operating, legislative, regulatory and other factors beyond their control. Any payments of dividends, distributions, loans or advances to us by the Guarantors could also be subject to restrictions on dividends under applicable local law in the jurisdictions in which the Guarantors operate. In the event that we do not receive distributions from the Guarantors, or to the extent that the earnings from, or other available assets of, the Guarantors are insufficient, we may be unable to make payments on the First Lien Notes.
Pledged Securities of Affiliates
Pursuant to the terms of the First Lien Notes collateral documents, the Collateral Agent under the Indenture may pursue remedies, or pursue foreclosure proceedings on the Collateral (including the equity of the Guarantors and other direct subsidiaries of Valaris Limited and the Guarantors), following an event of default under the Indenture. The Collateral Agent’s ability to exercise such remedies is limited by the intercreditor agreement for so long as any priority lien debt is outstanding.
The assets, liabilities and results of operations of the combined affiliates whose securities are pledged as collateral are not materially different than the corresponding amounts presented in Valaris Limited's consolidated financial statements, except with respect to (1) approximately $550.1 million of cash held at Valaris Limited and (2) the First Lien Notes and related accrued interest and interest expense. The value of the pledged equity is subject to fluctuations based on factors that include, among other things, general economic conditions and the ability to realize on the Collateral as part of a going concern and in an orderly fashion to available and willing buyers and outside of distressed circumstances. There is no trading market for the pledged equity interests.
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Under the terms of the Indenture and the other documents governing the obligations with respect to the First Lien Notes (the “Notes Documents”), Valaris Limited and the Guarantors will be entitled to the release of the Collateral from the liens securing the First Lien Notes under one or more circumstances, including (1) upon full and final payment of any such obligations; (2) to the extent that proceeds continue to constitute Collateral, in the event that Collateral is sold, transferred, disbursed or otherwise disposed of in accordance with the Notes Documents; (3) upon our exercise of legal defeasance, covenant defeasance or discharge under the Indenture; (4) with respect to vessels, certain specified events permitting release of the mortgage with respect to such vessels under the Indenture; (5) with the consent of the requisite holders under the Indenture; (6) with respect to equity interests in restricted subsidiaries that incur permitted indebtedness, if such equity interests shall secure such other indebtedness and the same is permitted under the terms of the Indenture; and (7) as provided in the intercreditor agreement. The collateral agency agreement also provides for release of the Collateral from the liens securing the Notes under the above-described circumstances (but including additional requirements for release in relation to all of the documents governing the indebtedness that is secured by first-priority liens on the Collateral, in addition to the Indenture). Upon the release of any subsidiary from its guarantee, if any, in accordance with the terms of the Indenture, the lien on any pledged equity interests issued by such Guarantor and on any assets of such Guarantor will automatically terminate.
Summarized Financial Information
The summarized financial information below reflects the combined accounts of the Guarantors and Valaris Limited (collectively, the “Obligors”), for the dates and periods indicated. The financial information is presented on a combined basis and intercompany balances and transactions between entities in the Obligor group have been eliminated.
Summarized Balance Sheet Information:
| (in millions) | December 31, 2022 | December 31, 2021 | |||||||||
| ASSETS | |||||||||||
| Current assets | $ | 1,288.3 | $ | 1,157.3 | |||||||
| Amounts due from non-guarantor subsidiaries, current | 625.5 | 729.7 | |||||||||
| Amounts due from related party, current | 13.5 | 13.1 | |||||||||
| Noncurrent assets | 1,061.1 | 1,019.0 | |||||||||
| Amounts due from non-guarantor subsidiaries, noncurrent | 896.7 | 1,469.7 | |||||||||
| LIABILITIES AND SHAREHOLDER'S EQUITY | |||||||||||
| Current liabilities | 416.7 | 335.9 | |||||||||
| Amounts due to non-guarantor subsidiaries, current | 8.2 | 55.3 | |||||||||
| Amounts due to related party, current | 43.2 | 38.3 | |||||||||
| Long-term debt | 542.4 | 545.3 | |||||||||
| Noncurrent liabilities | 431.2 | 436.4 | |||||||||
| Amounts due to non-guarantor subsidiaries, noncurrent | 1,767.8 | 1,921.6 | |||||||||
| Noncontrolling interest | 8.0 | 2.7 | |||||||||
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Summarized Statement of Operations Information:
| Successor | Predecessor | ||||||||||||||||
| (in millions) | Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | ||||||||||||||
| Operating revenues | $ | 1,471.6 | $ | 818.7 | $ | 388.8 | |||||||||||
| Operating revenues from related party | 58.7 | 36.9 | 23.1 | ||||||||||||||
| Operating costs and expenses | 1,505.9 | 818.3 | 1,272.9 | ||||||||||||||
| Reorganization expense | (2.4) | (15.5) | (3,584.1) | ||||||||||||||
| Income (loss) from continuing operations before income taxes | 72.3 | 184.9 | (4,343.4) | ||||||||||||||
| Net income attributable to noncontrolling interest | (5.3) | (3.8) | (3.2) | ||||||||||||||
| Net income (loss) | 67.0 | 181.1 | (4,346.6) | ||||||||||||||
Effects of Climate Change and Climate Change Regulation
Greenhouse gas (“GHG”) emissions have increasingly become the subject of international, national, regional, state and local attention. The United States reentered the Paris Agreement in February 2021. Further, in November 2021, the United States 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. It is expected that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, will be proposed and/or promulgated. For example, the current presidential administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the (1) Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (“EO 13990”) and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad (“EO 14008”). EO 13990 established an interagency working group to recommend methods for agencies to incorporate the “social cost of carbon” into regulatory analyses and directed the EPA to review various environmental regulations for consistency with the policies and goals set forth in EO 13990. EO 14008 announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority. Ongoing legal challenges have slowed or halted the implementation of such executive orders, and the full impact of these federal actions, or any other future restrictions or prohibitions, remains unclear.
In an effort to reduce GHG emissions, governments have implemented or considered legislative and regulatory mechanisms to institute carbon pricing mechanisms, such as the European Union’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, such as the SEC’s 2022 proposed rules for a climate change reporting framework.
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
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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 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. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our financial condition, operating results and cash flows in a manner different than our competitors.
Restrictions on GHG emissions or other related legislative or regulatory enactments could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.
In addition, in recent years the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, has promoted divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
MARKET RISK
Interest Rate Risk
Our outstanding debt at December 31, 2022 (Successor) consisted of our $550.0 million aggregate principal amount of First 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 Notes Receivable from ARO bear interest based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. As the Notes Receivable from ARO bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income for 2023 has already been determined. A hypothetical 1% decrease to LIBOR would decrease interest income for the year ended December 31, 2022 (Successor) by $4.0 million based on the principal amount outstanding at December 31, 2022 (Successor) of $402.7 million.
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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 as our unsecured foreign currency credit lines were terminated in the second quarter of 2020 and our access to other foreign currency credit lines is limited.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires us to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Concurrent with our emergence from bankruptcy, we applied fresh start accounting and elected to change our accounting policies related to property and equipment as well as materials and supplies. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" and "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information. 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
Concurrent with our emergence from bankruptcy, we applied fresh start accounting and adjusted the carrying value of our drilling rigs to estimated fair value. See "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information. As of December 31, 2022 (Successor), the carrying value of our property and equipment totaled $977.2 million, which represented 34% 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.
Upon emergence, we elected to change our accounting policies and 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
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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.
Property and equipment held-for-sale is recorded at the lower of net book value or fair value less cost to sell.
Our fleet of 16 floater rigs represented 50% of both the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2022 (Successor). Our fleet of 36 jackup rigs represented 46% of both the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2022.
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, 2022 (Successor), our Consolidated Balance Sheet included a $39.0 million net deferred income tax asset, a $31.1 million liability for income taxes currently payable and a $275.0 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
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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.
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, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2022 (Successor), included (1) a weighted average discount rate of 5.21% to determine pension benefit obligations, (2) a weighted average discount rate of 2.73% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.26% to determine net periodic pension cost. Upon emergence, our pension and other post retirement plans were remeasured as of the Effective Date. The assumed discount rate is based upon the average yield for Moody’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, 2022 (Successor), a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $60.1 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 $6.1 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 increased to 7.10% at December 31, 2022 (Successor) from 6.26% at December 31, 2021 (Successor). See "Note 12 - 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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information required under this Item 7A. has been incorporated herein from "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."
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Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2022 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, has issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.
February 21, 2023
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Valaris Limited:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Valaris Limited and subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income (loss), and cash flows for the year ended December 31, 2022 and for the period from May 1, 2021 to December 31, 2021 (Successor periods) and for the period from January 1, 2021 to April 30, 2021, and the year ended December 31, 2020 (Predecessor periods), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for Successor and Predecessor periods, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2023 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
New Basis of Presentation
As discussed in Note 1 to the consolidated financial statements, on March 3, 2021, the Bankruptcy Court for the Southern District of Texas entered an order confirming the Company’s plan for reorganization under Chapter 11, which became effective on April 30, 2021. Accordingly, the accompanying consolidated financial statements as of December 31, 2022 and 2021 and for the Successor periods have been prepared in conformity with Accounting Standards Codification 852, Reorganization, with the Company’s assets, liabilities, and capital structure having carrying amounts not comparable to prior years.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
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Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Income tax positions pertaining to certain tax transactions
As discussed in Note 1 and 13 to the consolidated financial statements, the Company evaluated the income tax effect of certain transactions which often requires local country tax expertise and judgment. This requires the Company to interpret complex tax laws in multiple jurisdictions to assess whether its tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities.
We identified the assessment of income tax positions pertaining to certain tax transactions as a critical audit matter. Complex auditor judgment was required to evaluate the Company’s assessment that certain tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities. In addition, specialized skills and knowledge were required to evaluate the Company’s interpretation of tax laws in the applicable jurisdictions.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s income tax process. This included controls related to the interpretation of tax laws applicable to certain transactions and the assessment that tax positions pertaining to those transactions have a more than 50 percent likelihood of being sustained with taxing authorities. We involved tax professionals with specialized skills and knowledge, who assisted on evaluating the Company’s interpretation of local tax laws and assessment of whether tax positions had a greater than 50 percent likelihood of being sustained with taxing authorities.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 21, 2023
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Valaris Limited:
Opinion on Internal Control Over Financial Reporting
We have audited Valaris Limited and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income (loss), and cash flows for the year ended December 31, 2022 and for the period from May 1, 2021 to December 31, 2021 (Successor periods) and for the period from January 1, 2021 to April 30, 2021, and the year ended December 21, 2020 (Predecessor periods), and the related notes (collectively, the consolidated financial statements), and our report dated February 21, 2023 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 21, 2023
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| OPERATING REVENUES | $ | 1,602.5 | $ | 835.0 | $ | 397.4 | $ | 1,427.2 | ||||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 1,383.2 | 724.1 | 343.8 | 1,470.4 | ||||||||||||||||||||||
| Loss on impairment | 34.5 | — | 756.5 | 3,646.2 | ||||||||||||||||||||||
| Depreciation | 91.2 | 66.1 | 159.6 | 540.8 | ||||||||||||||||||||||
| General and administrative | 80.9 | 58.2 | 30.7 | 214.6 | ||||||||||||||||||||||
| Total operating expenses | 1,589.8 | 848.4 | 1,290.6 | 5,872.0 | ||||||||||||||||||||||
| OTHER OPERATING INCOME | — | — | — | 118.1 | ||||||||||||||||||||||
| EQUITY IN EARNINGS (LOSSES) OF ARO | 24.5 | 6.1 | 3.1 | (7.8) | ||||||||||||||||||||||
| OPERATING INCOME (LOSS) | 37.2 | (7.3) | (890.1) | (4,334.5) | ||||||||||||||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||||||||||||
| Interest income | 65.5 | 28.5 | 3.6 | 19.7 | ||||||||||||||||||||||
Interest expense, net (Unrecognized contractual interest expense for debt subject to compromise was $132.9 million and $140.7 million for the four months ended April 30, 2021 and the year ended December 31, 2020, respectively) | (45.3) | (31.0) | (2.4) | (290.6) | ||||||||||||||||||||||
| Reorganization items, net | (2.4) | (15.5) | (3,584.6) | (527.6) | ||||||||||||||||||||||
| Other, net | 169.9 | 38.1 | 25.9 | 16.0 | ||||||||||||||||||||||
| 187.7 | 20.1 | (3,557.5) | (782.5) | |||||||||||||||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 224.9 | 12.8 | (4,447.6) | (5,117.0) | ||||||||||||||||||||||
| PROVISION (BENEFIT) FOR INCOME TAXES | ||||||||||||||||||||||||||
| Current income tax expense (benefit) | 35.2 | 57.7 | 34.4 | (153.7) | ||||||||||||||||||||||
| Deferred income tax expense (benefit) | 7.9 | (21.3) | (18.2) | (105.7) | ||||||||||||||||||||||
| 43.1 | 36.4 | 16.2 | (259.4) | |||||||||||||||||||||||
| NET INCOME (LOSS) | 181.8 | (23.6) | (4,463.8) | (4,857.6) | ||||||||||||||||||||||
| NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (5.3) | (3.8) | (3.2) | 2.1 | ||||||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO VALARIS | $ | 176.5 | $ | (27.4) | $ | (4,467.0) | $ | (4,855.5) | ||||||||||||||||||
| EARNINGS (LOSS) PER SHARE | ||||||||||||||||||||||||||
| Basic | $ | 2.35 | $ | (0.37) | $ | (22.38) | $ | (24.42) | ||||||||||||||||||
| Diluted | $ | 2.33 | $ | (0.37) | $ | (22.38) | $ | (24.42) | ||||||||||||||||||
| WEIGHTED-AVERAGE SHARES OUTSTANDING | ||||||||||||||||||||||||||
| Basic | 75.1 | 75.0 | 199.6 | 198.9 | ||||||||||||||||||||||
| Diluted | 75.6 | 75.0 | 199.6 | 198.9 | ||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| NET INCOME (LOSS) | $ | 181.8 | $ | (23.6) | $ | (4,463.8) | $ | (4,857.6) | ||||||||||||||||||
| OTHER COMPREHENSIVE INCOME (LOSS), NET | ||||||||||||||||||||||||||
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income (loss). | 23.8 | (9.1) | 0.1 | (76.3) | ||||||||||||||||||||||
| Net change in fair value of derivatives | — | — | — | (5.4) | ||||||||||||||||||||||
Amortization of settlement gain, net of income tax expense of $0.1 million for the year ended December 31, 2020 | — | — | — | (0.2) | ||||||||||||||||||||||
| Reclassification of net gains on derivative instruments from other comprehensive loss into net loss | — | — | (5.6) | (11.6) | ||||||||||||||||||||||
| Other | — | — | — | (0.6) | ||||||||||||||||||||||
| NET OTHER COMPREHENSIVE INCOME (LOSS) | 23.8 | (9.1) | (5.5) | (94.1) | ||||||||||||||||||||||
| COMPREHENSIVE INCOME (LOSS) | 205.6 | (32.7) | (4,469.3) | (4,951.7) | ||||||||||||||||||||||
| COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (5.3) | (3.8) | (3.2) | 2.1 | ||||||||||||||||||||||
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO VALARIS | $ | 200.3 | $ | (36.5) | $ | (4,472.5) | $ | (4,949.6) | ||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except par value amounts)
| December 31, 2022 | December 31, 2021 | |||||||||||||
| ASSETS | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents | $ | 724.1 | $ | 608.7 | ||||||||||
| Restricted cash | 24.4 | 35.9 | ||||||||||||
| Accounts receivable, net | 449.1 | 444.2 | ||||||||||||
| Other current assets | 148.6 | 117.8 | ||||||||||||
| Total current assets | 1,346.2 | 1,206.6 | ||||||||||||
| PROPERTY AND EQUIPMENT, AT COST | 1,134.5 | 957.0 | ||||||||||||
| Less accumulated depreciation | 157.3 | 66.1 | ||||||||||||
| Property and equipment, net | 977.2 | 890.9 | ||||||||||||
| LONG-TERM NOTES RECEIVABLE FROM ARO | 254.0 | 249.1 | ||||||||||||
| INVESTMENT IN ARO | 111.1 | 86.6 | ||||||||||||
| OTHER ASSETS | 171.8 | 169.9 | ||||||||||||
| $ | 2,860.3 | $ | 2,603.1 | |||||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Accounts payable - trade | $ | 256.5 | $ | 225.8 | ||||||||||
| Accrued liabilities and other | 247.9 | 196.2 | ||||||||||||
| Total current liabilities | 504.4 | 422.0 | ||||||||||||
| LONG-TERM DEBT | 542.4 | 545.3 | ||||||||||||
| OTHER LIABILITIES | 515.6 | 558.4 | ||||||||||||
| Total liabilities | 1,562.4 | 1,525.7 | ||||||||||||
| COMMITMENTS AND CONTINGENCIES | ||||||||||||||
| VALARIS SHAREHOLDERS' EQUITY | ||||||||||||||
Common shares, $0.01 par value, 700.0 shares authorized, 75.2 and 75.0 shares issued as of December 31, 2022 and 2021, respectively | 0.8 | 0.8 | ||||||||||||
Preference shares, $0.01 par value, 150.0 shares authorized, no shares issued as of December 31, 2022 and 2021 | — | — | ||||||||||||
| Stock warrants | 16.4 | 16.4 | ||||||||||||
| Additional paid-in capital | 1,097.9 | 1,083.0 | ||||||||||||
| Retained earnings (deficit) | 160.1 | (16.4) | ||||||||||||
| Accumulated other comprehensive income (loss) | 14.7 | (9.1) | ||||||||||||
| Total Valaris shareholders' equity | 1,289.9 | 1,074.7 | ||||||||||||
| NONCONTROLLING INTERESTS | 8.0 | 2.7 | ||||||||||||
| Total equity | 1,297.9 | 1,077.4 | ||||||||||||
| $ | 2,860.3 | $ | 2,603.1 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||||||||
| Net income (loss) | $ | 181.8 | $ | (23.6) | $ | (4,463.8) | $ | (4,857.6) | ||||||||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||||
| Gain on asset disposals | (141.2) | (21.2) | (6.0) | (11.8) | ||||||||||||||||||||||
| Depreciation expense | 91.2 | 66.1 | 159.6 | 540.8 | ||||||||||||||||||||||
| Accretion of discount on notes receivable | (44.9) | (20.8) | — | — | ||||||||||||||||||||||
| Loss on impairment | 34.5 | — | 756.5 | 3,646.2 | ||||||||||||||||||||||
| Equity in losses (earnings) of ARO | (24.5) | (6.1) | (3.1) | 7.8 | ||||||||||||||||||||||
| Share-based compensation expense | 17.4 | 4.3 | 4.8 | 21.4 | ||||||||||||||||||||||
| Net periodic pension and retiree medical income | (16.4) | (8.7) | (5.4) | (14.6) | ||||||||||||||||||||||
| Amortization, net | (9.0) | 2.3 | (4.8) | 6.2 | ||||||||||||||||||||||
| Deferred income tax expense (benefit) | 7.9 | (21.3) | (18.2) | (105.7) | ||||||||||||||||||||||
| Amortization of debt issuance cost | 1.0 | 0.5 | — | 36.8 | ||||||||||||||||||||||
| Adjustment to gain on bargain purchase | — | — | — | 6.3 | ||||||||||||||||||||||
| Debtor in possession financing fees and payments on Backstop Commitment Agreement | — | — | — | 40.0 | ||||||||||||||||||||||
| Non-cash reorganization items, net | — | — | 3,487.3 | 436.4 | ||||||||||||||||||||||
| Other | (1.6) | 0.3 | 7.3 | 30.2 | ||||||||||||||||||||||
| Changes in operating assets and liabilities | 35.4 | 4.7 | 68.5 | (22.0) | ||||||||||||||||||||||
| Contributions to pension plans and other post-retirement benefits | (4.1) | (2.7) | (22.5) | (12.1) | ||||||||||||||||||||||
| Net cash provided by (used in) operating activities | 127.5 | (26.2) | (39.8) | (251.7) | ||||||||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||||||||
| Purchases of short-term investments | (220.0) | — | — | — | ||||||||||||||||||||||
| Maturities of short-term investments | 220.0 | — | — | — | ||||||||||||||||||||||
| Additions to property and equipment | (207.0) | (50.2) | (8.7) | (93.8) | ||||||||||||||||||||||
| Net proceeds from disposition of assets | 150.3 | 25.1 | 30.1 | 51.8 | ||||||||||||||||||||||
| Repayments of note receivable from ARO | 40.0 | — | — | — | ||||||||||||||||||||||
| Net cash provided by (used in) investing activities | (16.7) | (25.1) | 21.4 | (42.0) | ||||||||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||||||||
| Consent solicitation fees | (3.9) | — | — | — | ||||||||||||||||||||||
| Payments for tax withholdings for share-based awards | (2.5) | — | — | — | ||||||||||||||||||||||
| Issuance of first lien notes | — | — | 520.0 | — | ||||||||||||||||||||||
| Payments to Predecessor creditors | — | — | (129.9) | — | ||||||||||||||||||||||
| Borrowings on credit facility | — | — | — | 596.0 | ||||||||||||||||||||||
| Debtor in possession financing fees and payments on Backstop Commitment Agreement | — | — | — | (40.0) | ||||||||||||||||||||||
| Repayments of credit facility borrowings | — | — | — | (15.0) | ||||||||||||||||||||||
| Reduction of long-term borrowings | — | — | — | (9.7) | ||||||||||||||||||||||
| Purchase of noncontrolling interest | — | — | — | (7.2) | ||||||||||||||||||||||
| Other | — | — | (1.4) | (1.9) | ||||||||||||||||||||||
| Net cash provided by (used in) financing activities | (6.4) | — | 388.7 | 522.2 | ||||||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | (0.5) | (0.1) | (0.1) | 0.1 | ||||||||||||||||||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS AND RESTRICTED CASH | 103.9 | (51.4) | 370.2 | 228.6 | ||||||||||||||||||||||
| CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, BEGINNING OF PERIOD | 644.6 | 696.0 | 325.8 | 97.2 | ||||||||||||||||||||||
| CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, END OF PERIOD | $ | 748.5 | $ | 644.6 | $ | 696.0 | $ | 325.8 | ||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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. We currently own 52 rigs, including 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 36 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional seven rigs. We also have options to purchase two recently constructed drillships on or before December 31, 2023.
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 current operations spanning six continents. The markets in which we operate include the Gulf of Mexico, South America, the North Sea, 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.
Chapter 11 Cases
On August 19, 2020 (the “Petition Date”), Valaris plc (“Legacy Valaris” or “Predecessor”) and certain of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for reorganization under chapter 11 of the United States Bankruptcy Code ("Bankruptcy Code") in the Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court") The Debtors obtained joint administration of their chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”).
In connection with the Chapter 11 Cases, on and prior to April 30, 2021 (the "Effective Date"), Legacy Valaris effectuated certain restructuring transactions, pursuant to which the successor company, Valaris, was formed and, through a series of transactions, Legacy Valaris transferred to a subsidiary of Valaris substantially all of the subsidiaries, and other assets, of Legacy Valaris.
References to the financial position and results of operations of the "Successor" or "Successor Company" relate to the financial position and results of operations of the Company after the Effective Date. References to the financial position and results of operations of the "Predecessor" or "Predecessor Company" refer to the financial position and results of operations of Legacy Valaris on and prior to the Effective Date. References to the “Company,” “we,” “us” or “our” in this Annual Report are to Valaris Limited, together with its consolidated subsidiaries, when referring to periods following the Effective Date, and to Legacy Valaris, together with its consolidated subsidiaries, when referring to periods prior to and including Effective Date.
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Fresh Start Accounting
On the Effective Date, the Debtors emerged from the Chapter 11 Cases. Upon emergence from the Chapter 11 Cases, we qualified for and adopted fresh start accounting. The application of fresh start accounting resulted in a new basis of accounting, and the Company became a new entity for financial reporting purposes. Accordingly, our financial statements and notes after the Effective Date are not comparable to our financial statements and notes on and prior to that date. Furthermore, the consolidated financial statements and notes have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
See “Note 2 – Chapter 11 Proceedings” and “Note 3 - Fresh Start Accounting” for additional details regarding the Chapter 11 Cases and fresh start accounting.
Basis of Presentation
The Company's financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The accompanying financial statements have been updated to reflect the correction of immaterial errors identified in the accounting for income and other taxes in periods prior to 2022. We determined that our provision for income taxes should have been $10.7 million lower in prior periods as a result of the misapplication of accounting literature as well as the use of incorrect interest rates on late payments related to unrecognized tax benefits for a specific jurisdiction. Also, $6.1 million of deferred tax assets should have been reduced with a corresponding reduction in our liability for unrecognized tax benefits as of December 31, 2021. Further, our contract drilling expense should have been $4.6 million lower in the eight months ended December 31, 2021 due to the expiration of the statute of limitations on a non-income tax related matter. Finally, we determined that certain loss carryback provisions of $1.3 million should have reduced our provision for income taxes for the year ended December 31, 2020. To correct these errors, we reduced Other assets and Other liabilities by $6.1 million and $22.7 million, respectively, as of December 31, 2021, and Contract drilling expense and Provision for income taxes by $4.6 million and $1.0 million, respectively, for the eight months ended December 31, 2021. A further adjustment of $11.0 million was recorded to reduce Retained deficit for the eight months ended December 31, 2021 to adjust for the cumulative effect of the errors to the Predecessor.
Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Valaris Limited, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. All intercompany accounts and transactions have been eliminated. Investments in operating entities in which we have the ability to exercise significant influence, but where we do not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our interest in ARO using the equity method of accounting and only recognize our portion of equity in earnings in our consolidated financial statements. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO.
Pervasiveness of Estimates
The preparation of financial statements in conformity with GAAP requires us to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.
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Foreign Currency Remeasurement and Translation
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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Most transaction gains and losses, including certain gains and losses on our prior derivative instruments, are included in Other, net, in our Consolidated Statements of Operations. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in Accumulated other comprehensive income on our Consolidated Balance Sheet. Net foreign currency exchange gains were $12.2 million, $8.1 million and $13.4 million, and were included in Other, net, in our Consolidated Statements of Operations for the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor) and four months ended April 30, 2021 (Predecessor), respectively. Net foreign currency exchange losses, inclusive of offsetting fair value derivatives were $11.0 million, and were included in Other, net, in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor).
Cash Equivalents and Short-Term Investments
Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year at the date of purchase are classified as short-term investments.
There were no short-term investments as of December 31, 2022 (Successor) and December 31, 2021 (Successor). Cash flows from purchases and maturities of short-term investments were classified as investing activities in our Consolidated Statements of Cash Flows for the year ended December 31, 2022. To mitigate our credit risk, our investments in time deposits have historically been diversified across multiple, high-quality financial institutions.
Property and Equipment
All costs incurred in connection with the acquisition, construction, major enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Costs incurred to place an asset into service are capitalized, including costs related to the initial mobilization of a newbuild drilling rig. Repair and maintenance costs are charged to contract drilling expense in the period in which they are incurred. Upon the sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet, and the resulting gain or loss is included in Other, net in our Consolidated Statements of Operations.
Upon emergence, we elected to change our accounting policies and 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.
Our property and equipment is depreciated on a straight-line basis, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from to 35 years. Buildings and improvements are depreciated over estimated useful lives ranging from 10 to 30 years. Other equipment, including computer and communications hardware and software, is depreciated over estimated useful lives ranging from to six years.
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, on a quarterly basis to identify events or changes in circumstances ("triggering events") that indicate that the carrying value of such rigs may not be recoverable. For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference
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between the carrying value of the asset and its estimated fair value. Property and equipment held-for-sale is recorded at the lower of net book value or fair value less cost to sell.
We recorded pre-tax, non-cash impairment losses related to long-lived assets of $34.5 million, $756.5 million and $3.6 billion, in the year ended December 31, 2022 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively. See "Note 7 - Property and Equipment" for additional information on our impairment charges.
Operating Revenues and Expenses
See "Note 4 - Revenue from Contracts with Customers" for information on our accounting policies for revenue recognition and certain operating costs that are deferred and amortized over future periods.
Derivative Instruments
We did not have any open derivative instruments as of December 31, 2022 (Successor) or 2021 (Successor). However, we have historically used derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 9 - Derivative Instruments" for additional information on how and why we used derivatives and the impact of the Chapter 11 Cases.
Derivatives are recorded on our Consolidated Balance Sheet at fair value. Derivatives subject to legally enforceable master netting agreements are not offset on our Consolidated Balance Sheet. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges and are effective in reducing the risk exposure that they are designated to hedge.
Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in accumulated other comprehensive income ("AOCI"). Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.
Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualifies as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in Other, net, in our Consolidated Statements of Operations based on the change in the fair value of the derivative. When a forecasted transaction becomes probable of not occurring, gains and losses on the derivative previously recorded in AOCI are reclassified currently into earnings and included in Other, net, in our Consolidated Statements of Operations.
Historically, we would enter into derivatives that hedge the fair value of recognized assets or liabilities but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, a natural hedging relationship generally exists where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other, net, in our Consolidated Statements of Operations.
Derivatives with asset fair values are reported in other current assets or other assets, net, on our Consolidated Balance Sheet depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities on our Consolidated Balance Sheet depending on maturity date.
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Income Taxes
We conduct operations and earn income in numerous countries. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.
We operate in certain jurisdictions where tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. 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. Interest and penalties relating to income taxes are included in Current income tax expense in our Consolidated Statements of Operations.
Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries through an intercompany rig sale. The pre-tax profit resulting from an intercompany rig sale is eliminated from our consolidated financial statements, and the carrying value of a rig sold in an intercompany transaction remains at historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. The income tax effects resulting from intercompany rig sales are recognized in earnings in the period in which the sale occurs.
In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years, as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized or derecognized.
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.
Share-Based Compensation
We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. Our Management Incentive Plan (the “MIP”) allows our board of directors to authorize share grants to be settled in cash, shares or a combination of shares and cash. Compensation expense for time-based share awards to be settled in shares is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Compensation expense for performance awards is recognized over the requisite service period using the accelerated method and is reduced for forfeited awards in the period in which the forfeitures occur. For our performance awards that cliff vest and require the employee to render service through the vesting date, even though attainment of performance objectives might be earlier, our expense under the accelerated method would be a ratable expense over the vesting period. Equity settled
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performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. The estimated probable outcome of attainment of the specified performance goals is based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate as it relates to performance objectives are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs, except in the case of objectives based on a market condition, such as our stock price. Compensation cost for awards based on a market performance objective is recognized as long as the requisite service period is completed and will not be reversed even if the market-based objective is never satisfied. Compensation expense for share awards to be settled in cash are recognized as liabilities and remeasured each quarter with a cumulative adjustment to compensation cost during the period based on changes in our share price. Any adjustments to the compensation cost recognized in our Consolidated Statements of Operations for awards that are forfeited are recognized in the period in which the forfeitures occur. See "Note 11 - Share Based Compensation" for additional information on our share-based compensation.
Pension and Other Post-retirement benefit plans
We measure our actuarially determined obligations and related costs for our defined benefit pension and other post-retirement plans, retiree life and medical supplemental plan benefits by applying assumptions, the most significant of which include long-term rate of return on plan assets, discount rates and mortality rates. For the long-term rate of return, we develop our assumptions regarding the expected rate of return on plan assets based on historical experience and projected long-term investment returns, and we weight the assumptions based on each plan's asset allocation. For the discount rate, we base our assumptions on a yield curve approach. Actual results may differ from the assumptions included in these calculations. If gains or losses exceed 10% of the greater of the plan assets or plan liabilities, we amortize such gains or losses into income over either the period of expected future service of active participants, or over the expected average remaining lifetime of all participants. We recognize gains or losses related to plan curtailments at the date the plan amendment or termination is adopted which may precede the effective date.
Fair Value Measurements
We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 6 - Fair Value Measurements" for additional information on the fair value measurement of certain of our assets and liabilities.
Noncontrolling Interests
Third-parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries. Noncontrolling interests are classified as equity on our Consolidated Balance Sheet, and net (income) loss attributable to noncontrolling interests is presented separately in our Consolidated Statements of Operations. For the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), all (income) loss attributable to noncontrolling interest was from continuing operations.
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Cancellation of Predecessor Equity and Issuance of Warrants
On the Effective Date and pursuant to the plan of reorganization, the Legacy Valaris Class A ordinary shares were cancelled and all agreements, instruments and other documents evidencing, relating or otherwise connected with any of Legacy Valaris' equity interests outstanding prior to the Effective Date, including all equity-based awards, were also cancelled. Also, in accordance with the plan of reorganization, the Company issued 5.6 million warrants (the "Warrants") to the former holders of Legacy Valaris' equity to purchase common shares of Valaris Limited with a nominal value of $0.01 per share (the "Common Shares"). The Warrants are exercisable for one Common Share per Warrant at an initial exercise price of $131.88 per Warrant, in each case as may be adjusted from time to time pursuant to the applicable warrant agreement. The Warrants are exercisable for a period of seven years and will expire on April 29, 2028.
Earnings Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during the period. Basic and diluted earnings per share ("EPS") for the Predecessor was calculated in accordance with the two-class method. Predecessor net loss attributable to Legacy Valaris used in our computations of basic and diluted EPS was adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS is calculated using the treasury stock method and for the Successor includes the effect of all potentially dilutive stock equivalents, including warrants, restricted stock unit awards and performance stock unit awards and for the Predecessor included the effect of all potentially dilutive stock options and excluded non-vested shares.
The following table is a reconciliation of the weighted-average shares used in our basic and diluted EPS computations for the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor) (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Income (loss) from continuing operations attributable to our shares | $ | 176.5 | $ | (27.4) | $ | (4,467.0) | $ | (4,855.5) | ||||||||||||||||||
| Weighted average shares outstanding: | ||||||||||||||||||||||||||
| Basic | 75.1 | 75.0 | 199.6 | 198.9 | ||||||||||||||||||||||
| Effect of stock equivalents | 0.5 | — | — | — | ||||||||||||||||||||||
| Diluted | 75.6 | 75.0 | 199.6 | 198.9 | ||||||||||||||||||||||
Anti-dilutive share awards totaling 192,000 were excluded from the computation of diluted EPS for the year ended December 31, 2022 (Successor).
Due to the net loss position during the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), our potentially dilutive instruments were not included in the computation of diluted EPS as the effect of including these shares in the calculation would have been anti-dilutive. Anti-dilutive shares totaling 600,000, 300,000 and 400,000, for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively, were excluded from the computation of diluted EPS.
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We have 5,470,970 Warrants outstanding as of December 31, 2022 (Successor) which are exercisable for one Common Share per Warrant at an initial exercise price of $131.88 per Warrant. The exercise of these Warrants into Common Shares would have a dilutive effect to the holdings of Valaris Limited's existing shareholders. These Warrants are anti-dilutive for all periods presented for the Successor.
The Predecessor previously had convertible senior notes due 2024 (the "2024 Convertible Notes") for which we had the option to settle in cash, shares or a combination thereof for the aggregate amount due upon conversion. On the Effective Date, pursuant to the plan of reorganization, all outstanding obligations under the 2024 Convertible Notes were cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization. However, if the Legacy Valaris average share price had exceeded the exchange price during a respective predecessor reporting period, an assumed number of shares required to settle the conversion obligation in excess of the principal amount would have been included in our denominator for the computation of diluted EPS using the treasury stock method. The Legacy Valaris average share price did not exceed the exchange price during the four months ended April 30, 2021 (Predecessor) or the year ended December 31, 2020 (Predecessor).
New Accounting Pronouncements
Recently adopted accounting pronouncements
Leases - In July 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments,” (“Update 2021-05”) which requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. Update 2021-05 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. We adopted this update effective January 1, 2022 using a prospective method, with no material impact to our consolidated financial statements.
Business Combinations - In October 2021, the FASB issued ASU No. 2021-08, “Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” (“Update 2021-08”). ASU No. 2021-08 requires an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606 and provides practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. The amendments also apply to contract assets and contract liabilities from other contracts to which the provisions of Topic 606 apply, such as contract liabilities for the sale of nonfinancial assets within the scope of Subtopic 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets. The FASB issued the update to improve the accounting for acquired revenue contracts with customers in a business combination. Update 2021-08 is effective for fiscal years beginning after December 15, 2022, and interim periods within those fiscal years, with early adoption permitted. We adopted Update 2021-08 effective January 1, 2023 with no material impact to our financial statements upon adoption.
Accounting pronouncements to be adopted
Reference Rate Reform - In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ("Update 2020-04"), which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments in Update 2020-04 apply only to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients and that are retained through the end of the hedging relationship. The provisions in Update 2020-04 are effective upon issuance and can be applied prospectively through December 31, 2022. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset
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Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022, to December 31, 2024. Our long-term notes receivable from ARO (the "Notes Receivable from ARO"), from which we generate interest income on a LIBOR-based rate, are impacted by the application of this standard. As the Notes Receivable from ARO bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income in 2023 has already been determined. We expect to be able to modify the terms of our Notes Receivable from ARO to a comparable interest rate before the applicable LIBOR rate is no longer available and as such, do not expect this standard to have a material impact to our consolidated financial statements.
With the exception of the updated standards discussed above, there have been no accounting pronouncements issued and not yet effective that have significance, or potential significance, to our consolidated financial statements.
2. CHAPTER 11 PROCEEDINGS
Chapter 11 Cases and Emergence from Chapter 11
On the Petition Date, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors obtained joint administration of the Chapter 11 Cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI). On March 3, 2021, the Bankruptcy Court confirmed the Debtors' chapter 11 plan of reorganization.
On the Effective Date, we successfully completed our financial restructuring and together with the Debtors emerged from the Chapter 11 Cases. Upon emergence from the Chapter 11 Cases, we eliminated $7.1 billion of debt and obtained a $520.0 million capital injection by issuing the first lien secured notes (the "First Lien Notes"). See “Note 8 - Debt" for additional information on the First Lien Notes. On the Effective Date, the Legacy Valaris Class A ordinary shares were cancelled and the Common Shares were issued. Also, former holders of Legacy Valaris' equity were issued Warrants to purchase Common Shares.
Below is a summary of the terms of the plan of reorganization:
•Appointed six new members to the Company's board of directors to replace all of the directors of Legacy Valaris, other than the director also serving as President and Chief Executive Officer at the Effective Date, who was re-appointed pursuant to the plan of reorganization. All but one of the seven directors became directors as of the Effective Date and one became a director on July 1, 2021.
•Obligations under Legacy Valaris's outstanding senior notes (the "Senior Notes") were cancelled and the related indentures were cancelled, except to the limited extent expressly set forth in the plan of reorganization and the holders thereunder received the treatment as set forth in the plan of reorganization;
•The Legacy Valaris revolving credit facility (the "Revolving Credit Facility") was terminated and the holders thereunder received the treatment as set forth in the plan of reorganization;
•Holders of the Senior Notes received their pro rata share of (1) 38.48%, or 28.9 million, of Common Shares and (2) approximately 97.6% of the subscription rights to participate in the rights offering (the "Rights Offering") through which the Company offered $550.0 million of the First Lien Notes, which includes the backstop premium;
•Holders of the Senior Notes who participated in the Rights Offering received their pro rata share of approximately 29.3%, or 22.0 million, of Common Shares, and senior noteholders who agreed to backstop the Rights Offering received their pro rata share of approximately 2.63%, or 2.0 million of Common Shares and approximately $48.8 million in First Lien Notes as a backstop premium;
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•Certain Revolving Credit Facility lenders ("RCF Lenders") who participated in the Rights Offering received their pro rata share of approximately 0.7%, or 0.5 million Common Shares, RCF Lenders who agreed to backstop the Rights Offering received their pro rata share of 0.07%, or 49,500 of Common Shares and approximately $1.2 million in First Lien Notes as a backstop premium;
•Senior noteholders, solely with respect to Pride International LLC's 6.875% senior notes due 2020 and 7.875% senior notes due 2040, Ensco International 7.20% Debentures due 2027, and the 4.875% senior notes due 2022, 4.75% senior notes due 2024, 7.375% senior notes due 2025, 5.4% senior notes due 2042 and 5.85% senior notes due 2044, received an aggregate cash payment of $26.0 million in connection with settlement of certain alleged claims against the Company;
•The two RCF Lenders who chose to participate in the Rights Offering received their pro rata share of (1) 5.3%, or 4.0 million Common Shares (2) approximately 2.427% of the First Lien Notes (and associated Common Shares), (3) $7.8 million in cash, and (4) their pro rata share of the backstop premium. The RCF Lenders who entered into the amended restructuring support agreement and elected not to participate in the Rights Offering received their pro rata share of (1) 22.980%, or 17.2 million of Common Shares and (2) $96.1 million in cash;
•Holders of general unsecured claims are entitled to receive payment in full within ninety days after the later of (a) the Effective Date and (b) the date such claim comes due;
•0.4 million Common Shares were issued and $5.0 million was paid to Daewoo Shipbuilding & Marine Engineering Co., Ltd (the "Shipyard");
•Legacy Valaris Class A ordinary shares were cancelled and holders received 5.6 million in Warrants exercisable for one Common Share per Warrant at initial exercise price of $131.88 per Warrant, in each case as may be adjusted from time to time pursuant to the applicable warrant agreement. The Warrants are exercisable for a period of seven years and will expire on April 29, 2028;
•All equity-based awards of Legacy Valaris that were outstanding were cancelled;
•On the Effective Date, Valaris Limited entered into a registration rights agreement with certain parties who received Common Shares;
•On the Effective Date, Valaris Limited entered into a registration rights agreement with certain parties who received First Lien Notes; and
•There were no borrowings outstanding against our debtor-in-possession ("DIP") facility and there were no DIP claims that were not due and payable on, or that otherwise survived, the Effective Date. The DIP Credit Agreement terminated on the Effective Date.
Management Incentive Plan
In accordance with the plan of reorganization, Valaris Limited adopted the 2021 Management Incentive Plan (the “MIP”) as of the Effective Date and authorized and reserved 9.0 million Common Shares for issuance pursuant to equity incentive awards to be granted under the MIP, which may be in the form of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and cash awards or any combination thereof. See "Note 11 - Share Based Compensation" for more information on awards granted under the MIP after the Effective date.
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Liabilities Subject to Compromise
The Debtors' pre-petition Senior Notes and related unpaid accrued interest as of the Petition Date were classified as Liabilities Subject to Compromise on our Consolidated Balance Sheets as of December 31, 2020 (Predecessor). The liabilities were reported at the amounts that were expected to be allowed as claims by the Bankruptcy Court.
Liabilities subject to compromise at December 31, 2020 (Predecessor) consisted of the following (in millions):
6.875% Senior notes due 2020 | $ | 122.9 | ||||||
4.70% Senior notes due 2021 | 100.7 | |||||||
4.875% Senior notes due 2022 | 620.8 | |||||||
3.00% Exchangeable senior notes due 2024 | 849.5 | |||||||
4.50% Senior notes due 2024 | 303.4 | |||||||
4.75% Senior notes due 2024 | 318.6 | |||||||
8.00% Senior notes due 2024 | 292.3 | |||||||
5.20% Senior notes due 2025 | 333.7 | |||||||
7.375% Senior notes due 2025 | 360.8 | |||||||
7.75% Senior notes due 2026 | 1,000.0 | |||||||
7.20% Debentures due 2027 | 112.1 | |||||||
7.875% Senior notes due 2040 | 300.0 | |||||||
5.40% Senior notes due 2042 | 400.0 | |||||||
5.75% Senior notes due 2044 | 1,000.5 | |||||||
5.85% Senior notes due 2044 | 400.0 | |||||||
| Amounts drawn under the Revolving Credit Facility | 581.0 | |||||||
| Accrued Interest on Senior Notes and Revolving Credit Facility | 203.5 | |||||||
Rig holding costs(1) | 13.9 | |||||||
| Total liabilities subject to compromise | $ | 7,313.7 | ||||||
(1) Represents the holding costs incurred to maintain VALARIS DS-13 and VALARIS DS-14 in the shipyard.
All series of our senior notes, the 7.20% Debentures due 2027 and 2024 Convertible Notes together are referred to as the "Senior Notes".
The contractual interest expense on the outstanding Senior Notes and the Revolving Credit Facility was in excess of recorded interest expense by $132.9 million and $140.7 million for the four months ended April 30, 2021 (Predecessor) and for the year ended December 31, 2020 (Predecessor), respectively. This excess contractual interest was not included as interest expense on our Consolidated Statements of Operations as we had discontinued accruing interest on the Predecessor's Senior Notes and Revolving Credit Facility subsequent to the Petition Date. The Predecessor discontinued making interest payments on the Senior Notes beginning in June 2020.
Pre-petition Charges
We have reported the backstop commitment fee and legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date, as General and administrative expenses in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor) in the amount of $64.7 million.
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Reorganization Items
Expenditures, gains and losses that are realized or incurred by the Debtors as of or subsequent to the Petition Date and as a direct result of the Chapter 11 Cases are reported as Reorganization items, net in our Consolidated Statements of Operations for the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor). These costs include legal and other professional advisory service fees pertaining to the Chapter 11 Cases, contract items related to rejecting and amending certain operating leases ("Contract items") and the effects of the emergence from bankruptcy, including the application of fresh start accounting. Additionally, Reorganization items, net for the year ended December 31, 2020 (Predecessor) included all adjustments made to the carrying amount of certain pre-petition liabilities reflecting claims that were expected to be allowed by the Bankruptcy Court and DIP facility fees.
The components of reorganization items, net were as follows (in millions):
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | ||||||||||||||||||||||||||
| Professional fees | $ | 2.4 | $ | 17.2 | $ | 93.4 | $ | 66.8 | |||||||||||||||||||||
| DIP facility fees | — | — | — | 20.0 | |||||||||||||||||||||||||
| Contract items | — | (1.7) | 3.9 | 4.4 | |||||||||||||||||||||||||
| Reorganization items (fees) | 2.4 | 15.5 | 97.3 | 91.2 | |||||||||||||||||||||||||
| Write-off of unamortized debt discounts, premiums and issuance costs | — | — | — | 447.9 | |||||||||||||||||||||||||
| Contract items | — | — | 0.5 | (11.5) | |||||||||||||||||||||||||
| Backstop premium | — | — | 30.0 | — | |||||||||||||||||||||||||
| Gain on settlement of liabilities subject to compromise | — | — | (6,139.0) | — | |||||||||||||||||||||||||
| Issuance of Common Shares for backstop premium | — | — | 29.1 | — | |||||||||||||||||||||||||
| Issuance of Common Shares to the Shipyard | — | — | 5.4 | — | |||||||||||||||||||||||||
| Write-off of unrecognized share-based compensation expense | — | — | 16.0 | — | |||||||||||||||||||||||||
| Impact of newbuild contract amendments | — | — | 350.7 | — | |||||||||||||||||||||||||
| Loss on fresh start adjustments | — | — | 9,194.6 | — | |||||||||||||||||||||||||
| Reorganization items (non-cash) | — | — | 3,487.3 | 436.4 | |||||||||||||||||||||||||
| Total reorganization items, net | $ | 2.4 | $ | 15.5 | $ | 3,584.6 | $ | 527.6 | |||||||||||||||||||||
| Reorganization items (fees) paid | $ | 2.4 | $ | 14.7 | $ | 59.0 | $ | 30.0 | |||||||||||||||||||||
| Reorganization items (fees) unpaid | $ | — | $ | 0.8 | $ | 38.3 | $ | 61.2 | |||||||||||||||||||||
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3. FRESH START ACCOUNTING
Applicability of Fresh Start Accounting
Upon emergence from bankruptcy, we qualified for and applied fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes because (1) the holders of the then existing Class A ordinary shares of the Predecessor received less than 50 percent of the Common Shares of the Successor outstanding upon emergence and (2) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the total of all post-petition liabilities and allowed claims.
The reorganization value derived from the range of enterprise values associated with the plan of reorganization was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values (except for deferred income taxes). The amount of deferred income taxes recorded was determined in accordance with the applicable income tax accounting standard. The April 30, 2021 fair values of the Company’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets.
Reorganization Value
The reorganization value represents the fair value of the Successor's total assets and was derived from the enterprise value associated with the plan of reorganization, which represents the estimated fair value of an entity's long-term debt and equity less unrestricted cash upon emergence from chapter 11. As set forth in the disclosure statement and approved by the Bankruptcy Court, third-party valuation advisors estimated the enterprise value to be between $1,860.0 million and $3,145.0 million. The enterprise value range of the reorganized Debtors was determined primarily by using a discounted cash flow analysis. The value agreed in the plan of reorganization is indicative of an enterprise value at the low end of this range, or $1,860.0 million.
The following table reconciles the enterprise value to the estimated fair value of Successor Common Shares as of the Effective Date (in millions, except per share value):
| April 30, 2021 | |||||
| Enterprise Value | $ | 1,860.0 | |||
| Plus: Cash and cash equivalents | 607.6 | ||||
| Less: Fair value of debt | (544.8) | ||||
| Less: Warrants | (16.4) | ||||
| Less: Noncontrolling interest | 1.1 | ||||
| Less: Pension and other post-retirement benefits liabilities | (189.0) | ||||
| Less: Adjustments not contemplated in Enterprise Value | (639.0) | ||||
| Fair value of Successor Common Shares | $ | 1,079.5 | |||
| Shares issued upon emergence | 75.0 | ||||
| Per share value | $ | 14.39 | |||
The following table reconciles the enterprise value to the reorganization value as of the Effective Date (in millions):
| April 30, 2021 | |||||
| Enterprise Value | $ | 1,860.0 | |||
| Plus: Cash and cash equivalents | 607.6 | ||||
| Plus: Non-interest bearing current liabilities | 346.0 | ||||
| Less: Adjustments not contemplated in Enterprise Value | (218.0) | ||||
| Reorganization value of Successor assets | $ | 2,595.6 | |||
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Adjustments not contemplated in Enterprise Value represent certain obligations of the Successor that were either not contemplated or contemplated in a different amount in the forecasted cash flows of the enterprise valuation performed by third-party valuation advisors that, had they incorporated those anticipated cash flows into their analysis, the resulting valuation would have been different. For the reconciliation of Reorganization value of Successor assets, this item includes certain tax balances, contract liabilities, as well as an adjustment for the fair value of pension obligations. The reconciliation to Successor Common Share value includes these same reconciling items as well as other current and non-current liabilities of the Successor at the emergence.
The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in the valuation utilizing assumptions regarding future day rates, utilization, operating costs and capital requirements as of the emergence date. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
Valuation Process
The fair values of the Company's principal assets and liabilities including property, plant and equipment as well as our 50% equity interest in ARO and our Notes Receivable from ARO, options to purchase VALARIS DS-13 and VALARIS DS-14 (the "Newbuild Drillships"), the First Lien Notes, pensions and Warrants were estimated with the assistance of third-party valuation advisors.
Property, Plant and Equipment
The valuation of the Company’s drilling rigs was estimated by using an income approach or estimated sales price. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including, in the case of an income approach, assumptions regarding future day rates, utilization, operating costs, reactivation costs and capital requirements. In developing these assumptions, forecasted day rates and utilization took into account current market conditions and our anticipated business outlook. The cash flows were discounted at our weighted average cost of capital, which was derived from a blend of our after-tax cost of debt and our cost of equity, and computed using public share price information for similar offshore drilling market participants, certain U.S. Treasury rates and certain risk premiums specific to the Company.
Our remaining property and equipment, including owned real estate and other equipment, was valued using a cost approach, in which the estimated replacement cost of the assets was adjusted for physical depreciation and obsolescence, where applicable, to arrive at estimated fair value.
The estimated fair value of our property and equipment includes an adjustment to reconcile to our reorganization value.
Notes Receivable from ARO
The fair value of the Notes Receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the Notes Receivable from ARO using a discount rate based on a comparable yield with a country-specific risk premium.
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Investment in ARO
We estimated the fair value of the equity investment in ARO primarily by applying an income approach, using projected discounted cash flows of the underlying assets, a risk-adjusted discount rate and an estimated effective income tax rate.
Options to Purchase Newbuild Drillships
The fair value of the options to purchase Newbuild Drillships was estimated using an option pricing model utilizing the estimated fair value of a newbuild rig, estimated purchase price upon exercise of the options, the holding period, equity volatility and the risk-free rate.
First Lien Notes
The fair value of the First Lien Notes was determined to approximate the par value based on third-party valuation advisors’ analysis of the Company’s collateral coverage, financial metrics, and interest rate for the First Lien Notes relative to market rates of recent placements of a similar term for industry participants with similar credit risk.
Pensions
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, annual compensation increases, mortality rates and other factors. Upon emergence, our pension and other post retirement plans were remeasured as of the Effective Date. Key assumptions at the Effective Date included (1) a weighted average discount rate of 2.81% to determine pension benefit obligations and (2) an expected long-term rate of return on pension plan assets of 6.03% to determine net periodic pension cost.
Warrants
The fair value of the Warrants was determined using an option pricing model considering the contractual terms of the Warrant issuance. The key market data assumptions for the option pricing model are the estimated volatility and the risk-free rate. The volatility assumption was estimated using market data for offshore drilling market participants with consideration for differences in leverage. The risk-free rate assumption was based on U.S. Treasury Constant Maturity rates with a comparable term.
Condensed Consolidated Balance Sheet
The adjustments included in the following Condensed Consolidated Balance Sheet reflect the effects of the transactions contemplated by the plan of reorganization and executed by the Company on the Effective Date (reflected in the column “Reorganization Adjustments”), and fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Accounting Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded.
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| As of April 30, 2021 | |||||||||||||||||||||||
| Predecessor | Reorganization Adjustments | Fresh Start Accounting Adjustments | Successor | ||||||||||||||||||||
| ASSETS | |||||||||||||||||||||||
| CURRENT ASSETS | |||||||||||||||||||||||
| Cash and cash equivalents | $ | 280.2 | $ | 327.4 | (a) | $ | — | $ | 607.6 | ||||||||||||||
| Restricted cash | 45.7 | 42.7 | (b) | — | 88.4 | ||||||||||||||||||
| Accounts receivable, net | 425.9 | — | — | 425.9 | |||||||||||||||||||
| Other current assets | 370.1 | 1.5 | (c) | (281.1) | (o) | 90.5 | |||||||||||||||||
| Total current assets | 1,121.9 | 371.6 | (281.1) | 1,212.4 | |||||||||||||||||||
| PROPERTY AND EQUIPMENT, NET | 10,026.4 | (417.6) | (d) | (8,699.7) | (p) | 909.1 | |||||||||||||||||
| LONG-TERM NOTES RECEIVABLE FROM ARO | 442.7 | — | (214.4) | (q) | 228.3 | ||||||||||||||||||
| INVESTMENT IN ARO | 123.9 | — | (43.4) | (r) | 80.5 | ||||||||||||||||||
| OTHER ASSETS | 166.4 | (10.0) | (e) | 8.9 | (s) | 165.3 | |||||||||||||||||
| $ | 11,881.3 | $ | (56.0) | $ | (9,229.7) | $ | 2,595.6 | ||||||||||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||||||||||||||
| CURRENT LIABILITIES | |||||||||||||||||||||||
| Accounts payable - trade | $ | 161.5 | $ | 13.1 | (f) | $ | (0.5) | (t) | $ | 174.1 | |||||||||||||
| Accrued liabilities and other | 290.7 | (12.4) | (g) | (61.8) | (u) | 216.5 | |||||||||||||||||
| Total current liabilities | 452.2 | 0.7 | (62.3) | 390.6 | |||||||||||||||||||
| LONG-TERM DEBT | — | 544.8 | (h) | — | 544.8 | ||||||||||||||||||
| OTHER LIABILITIES | 706.2 | (55.2) | (i) | (85.6) | (v) | 565.4 | |||||||||||||||||
| Total liabilities not subject to compromise | 1,158.4 | 490.3 | (147.9) | 1,500.8 | |||||||||||||||||||
| LIABILITIES SUBJECT TO COMPROMISE | 7,313.7 | (7,313.7) | (j) | — | — | ||||||||||||||||||
| COMMITMENTS AND CONTINGENCIES | |||||||||||||||||||||||
| VALARIS SHAREHOLDERS' EQUITY | |||||||||||||||||||||||
| Predecessor Class A ordinary shares | 82.5 | (82.5) | (k) | — | — | ||||||||||||||||||
| Predecessor Class B ordinary shares | 0.1 | (0.1) | (k) | — | — | ||||||||||||||||||
| Successor common shares | — | 0.8 | (l) | — | 0.8 | ||||||||||||||||||
| Successor stock warrants | — | 16.4 | (m) | — | 16.4 | ||||||||||||||||||
| Predecessor additional paid-in capital | 8,644.0 | (8,644.0) | (k) | — | — | ||||||||||||||||||
| Successor additional paid-in capital | — | 1,078.7 | (l) | — | 1,078.7 | ||||||||||||||||||
| Retained deficit | (5,147.4) | 14,322.6 | (n) | (9,175.2) | (w) | — | |||||||||||||||||
| Accumulated other comprehensive loss | (93.4) | — | 93.4 | (x) | — | ||||||||||||||||||
| Predecessor treasury shares | (75.5) | 75.5 | (k) | — | — | ||||||||||||||||||
| Total Valaris shareholders' equity | 3,410.3 | 6,767.4 | (9,081.8) | 1,095.9 | |||||||||||||||||||
| NONCONTROLLING INTERESTS | (1.1) | — | — | (1.1) | |||||||||||||||||||
| Total equity | 3,409.2 | 6,767.4 | (9,081.8) | 1,094.8 | |||||||||||||||||||
| $ | 11,881.3 | $ | (56.0) | $ | (9,229.7) | $ | 2,595.6 | ||||||||||||||||
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Reorganization Adjustments
(a) Cash
Represents the reorganization adjustments (in millions):
| Receipt of cash for First Lien Notes | $ | 500.0 | |||
| Loan proceeds from backstop lenders | 20.0 | ||||
| Funds received for liquidation of rabbi trust related to certain employee benefits | 17.6 | ||||
| Payments to Predecessor creditors | (129.9) | ||||
| Transfer of funds for payment of certain professional fees to escrow account | (42.7) | ||||
| Payment for certain professional services fees | (29.0) | ||||
| Various other | (8.6) | ||||
| $ | 327.4 | ||||
(b) Restricted cash
Reflects the reorganization adjustment to record the transfer of cash for payment of certain professional fees to restricted cash, which will be held in escrow until billings from professionals have been received and reconciled at which time the funds in the account will be released.
(c) Other current asset
Reflects certain prepayments incurred upon emergence.
(d) Property and Equipment, net
Reflects the reorganization adjustment to remove $417.6 million of work-in-process related to the Newbuild Drillships. These values have been removed from property and equipment, net, based on the terms of the amended agreements with the Shipyard. As a result of the option to take delivery, we removed the historical work-in-process balances from the balance sheet.
(e) Other assets
Represents the reorganization adjustments (in millions):
| Liquidation of rabbi trust related to certain employee benefits | $ | (17.6) | |||
| Elimination of right-of-use asset associated with Newbuild Drillships | (5.5) | ||||
| Fair value of options to purchase Newbuild Drillships | 13.1 | ||||
| $ | (10.0) | ||||
Our supplemental executive retirement plans (the "SERP") are non-qualified plans that provided eligible employees an opportunity to defer a portion of their compensation for use after retirement. The SERP was frozen to the entry of new participants in November 2019 and to future compensation deferrals as of January 1, 2020. Upon emergence, assets previously held in a rabbi trust maintained for the SERP were liquidated and the SERP was amended.
In accordance with the amended agreement with the Shipyard, our leases were terminated and we have eliminated the historical right-of-use asset associated with the berthing locations of Newbuild Drillships.
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Additionally, upon effectiveness of the plan of reorganization, the amended agreement with the Shipyard provides the Company with the option to purchase the Newbuild Drillships. The reorganization adjustments include an asset that reflects the fair value of the option to purchase the Newbuild Drillships and embedded feature related to the ability, under the amended agreements with the Shipyard, for the equity issued pursuant to this arrangement to be put to the Company for $8.0 million of consideration for each rig, should we choose to take delivery.
(f) Accounts payable - trade
Reflects the following reorganization adjustments (in millions):
| Professional fees incurred upon emergence | $ | 26.1 | |||
| Payment of professional fees incurred prior to emergence | (12.6) | ||||
| Payment of certain accounts payable incurred prior to emergence | (0.4) | ||||
| $ | 13.1 | ||||
(g) Accrued liabilities and other
Reflects the following reorganization adjustments (in millions):
| Elimination of lease liabilities associated with Newbuild Drillships | $ | (5.0) | |||
| Elimination of accrued post-petition holding costs associated with Newbuild Drillships | (4.1) | ||||
| Payment of certain accrued liabilities incurred prior to emergence | (3.3) | ||||
| $ | (12.4) | ||||
In accordance with the amended agreement with the Shipyard, our leases were terminated and we have eliminated the historical lease liability associated with the berthing locations of Newbuild Drillships. Accrued post-petition holding costs have also been eliminated as a result of the amendments made effective upon emergence. Additionally, reorganization adjustments to accrued liabilities and other includes an amount primarily related to payment of professional fees incurred prior to emergence.
(h) Long-term debt
Reflects the reorganization adjustment to record the issuance of the $550.0 million aggregate principal amount of First Lien Notes and debt issuance costs of $5.2 million.
(i) Other liabilities
Reflects the following reorganization adjustments (in millions):
| Elimination of construction contract intangible liabilities associated with Newbuild Drillships | $ | (49.9) | |||
| Elimination of accrued post-petition holding costs associated with Newbuild Drillships | (4.7) | ||||
| Elimination of lease liabilities associated with Newbuild Drillships | (0.6) | ||||
| $ | (55.2) | ||||
The reorganization adjustments to other liabilities primarily relate to the elimination of construction contract intangible liabilities associated with the Newbuild Drillships. These construction contract intangible liabilities were recorded in purchase accounting for the original contracting entity. As the amended contract is
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structured as an option whereby we have the right, not the obligation to take delivery of the rigs, there is no longer an intangible liability associated with the contracts.
We have eliminated the historical lease liability associated with the berthing locations of Newbuild Drillships and accrued post-petition holding costs as described in (g) above.
(j) Liabilities subject to compromise
Reflects the following reorganization adjustments (in millions):
| Settlement of liabilities subject to compromise | $ | 7,313.7 | |||
| Issuance of common stock to Predecessor creditors | (721.0) | ||||
| Issuance of common stock to backstop parties | (323.8) | ||||
| Payments to Predecessor creditors | (129.9) | ||||
| Gain on settlement of liabilities subject to compromise | $ | 6,139.0 | |||
(k) Predecessor ordinary shares, additional paid-in capital and treasury shares
Represents the cancellation of the Predecessor's ordinary shares of $82.6 million, additional paid-in capital of $8,644.0 million and treasury stock of $75.5 million.
(l) Successor common shares and additional paid-in capital
Represents par value of 75.0 million new Common Shares of $0.8 million and capital in excess of par value of $1,078.7 million.
(m) Successor stock warrants
On the Effective Date and pursuant to the plan of reorganization, Valaris Limited issued an aggregate of 5.6 million Warrants exercisable for up to an aggregate of 5.6 million Common Shares to former holders of Legacy Valaris's equity interests. The fair value of the Warrants as of the Effective Date was $16.4 million.
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(n) Retained deficit
Represents the reorganization adjustments to total equity as follows (in millions):
| Gain on settlement of liabilities subject to compromise | $ | (6,139.0) | |||
| Issuance of Common Shares for backstop premium | 29.1 | ||||
| Issuance of Common Shares to the Shipyard | 5.4 | ||||
| Write-off of unrecognized share-based compensation expense | 16.0 | ||||
| Professional fees and success fees | 35.9 | ||||
| Backstop premium | 30.0 | ||||
| Impact of newbuild contract amendments | 350.7 | ||||
| Reorganization items, net | (5,671.9) | ||||
| Cancellation of Predecessor common shares | (82.6) | ||||
| Cancellation of Predecessor treasury shares | 75.5 | ||||
| Cancellation of Predecessor additional paid in capital | (7,856.4) | ||||
| Cancellation of equity component of Predecessor convertible notes | (220.0) | ||||
| Cancellation of Predecessor cash and equity compensation plans | (583.6) | ||||
| Fair value of Warrants | 16.4 | ||||
| $ | (14,322.6) | ||||
Fresh Start Adjustments
(o) Other current assets
Reflects the fresh start adjustments to record the estimated fair value of other current assets as follows (in millions):
| Elimination of materials and supplies | $ | (260.8) | |||
| Elimination of historical deferred contract drilling expenses | (20.3) | ||||
| $ | (281.1) | ||||
Primarily reflects the fresh start adjustment to eliminate the historical balance for materials and supplies as the result of a change in accounting policies upon emergence. Historically, we recognized materials and supplies on the balance sheet when purchased and subsequently expensed items when consumed. Upon emergence from bankruptcy, we elected to change our accounting policies related to materials and supplies whereby materials and supplies will be expensed as a period cost when received. Additionally, a customer arrangement provides that we take title to their materials and supplies for the duration of the contract and return or pay cash for them at the termination of the contract. Together with our policy change on materials and supplies, we elected to record these assets and the obligation to our customer on a net basis as opposed to a gross basis.
The fresh start adjustment for the elimination of historical deferred contract drilling expenses primarily relates to deferred mobilization costs, deferred contract preparation costs and deferred certification costs. Costs incurred for mobilization and contract preparation prior to the commencement of drilling services are deferred and subsequently amortized over the term of the related drilling contract. Additionally, we must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized on a straight-line basis over the corresponding certification periods. These deferred costs have no future economic benefit and are eliminated from the fresh start financial statements.
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(p) Property and equipment, net
Reflects the fresh start adjustments to historical amounts to record the estimated fair value of property and equipment.
Furthermore, upon emergence from bankruptcy, we elected to change our accounting policies and 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. Prior to emergence, we recorded our drilling rigs as a single asset with a useful life ascribed by the expected useful life of that asset.
(q) Notes Receivable from ARO
Reflects the fresh start adjustment to record the estimated fair value of the Notes Receivable from ARO. The fair value of the Notes Receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the Notes Receivable from ARO using a discount rate based on comparable yield with a country-specific risk premium.
(r) Investment in ARO
Reflects the fresh start adjustment to record the estimated fair value of the equity investment in ARO.
(s) Other assets
Reflects the fresh start adjustments to record the estimated fair value of other assets as follows (in millions):
| Deferred tax impacts of certain fresh start adjustments | $ | 21.1 | |||
| Fair value of contracts with customers | 8.5 | ||||
| Fair value adjustments to right-of-use assets | 0.4 | ||||
| Elimination of historical deferred contract drilling expenses | (16.5) | ||||
| Elimination of other deferred costs | (4.6) | ||||
| $ | 8.9 | ||||
The fresh start adjustment for deferred income tax assets represents the estimated incremental deferred income taxes, which reflects the tax effect of the differences between the estimated fair value of certain assets and liabilities recorded under fresh start accounting and the carryover tax basis of those assets and liabilities.
The fresh start adjustment to record the estimated fair value of contracts with customers represents the intangible assets recognized for firm customer contracts in place at the Effective Date that have favorable contract terms as compared to current market day rates for comparable drilling rigs. The various factors considered in the adjustment are (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the emergence date. The intangible assets are computed based on the present value of the difference in cash inflows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate. This balance will be amortized to operating revenues over the respective remaining contract terms on a straight-line basis.
The fresh start adjustment to right-of-use assets reflects the remeasuring of our operating leases as of the emergence date. Certain operating leases had unfavorable terms as of the emergence date, and as a result the right-of-use asset for such leases does not equal the lease liability upon emergence.
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The fresh start adjustment to eliminate historical deferred contract drilling expenses reflects the noncurrent portion of historical deferred contract drilling expenses described in (o) above as well as the elimination of customer contract intangibles previously recorded in purchase accounting for a 2019 transaction.
The fresh start adjustments to eliminate other deferred costs reflect non-operational deferred costs that have no future economic benefit.
(t) Accounts payable - trade
The fresh start adjustment to accounts payable trade reflects the write off of certain deferred amounts related to our operating leases. This value was eliminated through the remeasurement of our leases as of the emergence date.
(u) Accrued liabilities and other
Reflects the fresh start adjustments to record the estimated fair value of current liabilities as follows (in millions):
| Elimination of customer payable balance | $ | (36.8) | |||
| Elimination of historical deferred revenues | (25.9) | ||||
| Fair value of contracts with customers | 0.5 | ||||
| Fair value adjustment to lease liabilities | 0.4 | ||||
| $ | (61.8) | ||||
The fresh start adjustment to eliminate the customer payable balance is related to the change in accounting policy to present the balance on a net basis.
The fresh start adjustment to eliminate historical deferred revenues is primarily related to amounts previously received for the reimbursement for capital upgrades, upfront contract deferral fees and mobilization. Such amounts are deferred and subsequently amortized over the term of the related drilling contract. The deferred revenue does not represent any future performance obligations and is therefore eliminated as a fresh start accounting adjustment.
The fresh start adjustment to record the estimated fair value of contracts with customers reflects the intangible liabilities recognized for firm customer contracts in place at the Effective Date that have unfavorable contract terms as compared to current market day rates for comparable drilling rigs. The various factors considered in the adjustment are (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the emergence date. The intangible liabilities are computed based on the present value of the difference in cash inflows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate. This balance will be amortized to operating revenues over the respective remaining contract terms on a straight-line basis.
The fresh start adjustment to lease liabilities reflects the remeasuring of our operating leases as of the Effective Date.
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(v) Other liabilities
Reflects the fresh start adjustments to record the estimated fair value of other liabilities as follows (in millions):
| Adjustment to fair value of pension and other post-retirement plan liabilities | $ | (82.7) | |||
| Elimination of historical deferred revenue | (5.9) | ||||
| Deferred tax impacts of certain fresh start adjustments | 1.7 | ||||
| Fair value adjustments to lease liabilities | 1.1 | ||||
| Fair value adjustments to other liabilities | 0.2 | ||||
| $ | (85.6) | ||||
The fresh start adjustment to fair value pension and other post-retirement plan liabilities results from the remeasurement of the pension and other post-retirement benefit plans at the emergence date.
The fresh start adjustment to eliminate deferred revenues reflects the noncurrent portion of deferred revenues described in (u) above.
The fresh start adjustment for deferred income tax liabilities represents the estimated incremental deferred taxes, which reflects the tax effect of the differences between the estimated fair value certain assets and liabilities recorded under fresh start accounting and the carryover tax basis of those assets and liabilities.
The fresh start adjustment to lease liabilities reflects the remeasuring of our operating leases as of the Effective Date.
(w) Retained Deficit
Reflects the fresh start adjustments to retained deficit as follows (in millions):
| Fair value adjustments to prepaid and other current assets | $ | (281.1) | |||
| Fair value adjustments to property | (8,699.7) | ||||
| Fair value of intangible assets | 8.5 | ||||
| Fair value adjustment to investment in ARO | (43.4) | ||||
| Fair value adjustment to note receivable from ARO | (214.4) | ||||
| Fair value adjustments to other assets | (20.7) | ||||
| Fair value adjustments to other current liability | 62.8 | ||||
| Fair value of intangible liabilities | (0.5) | ||||
| Fair value adjustment to other liabilities | 87.3 | ||||
| Elimination of Predecessor accumulated other comprehensive loss | (93.4) | ||||
| Total fresh start adjustments included in reorganization items, net | $ | (9,194.6) | |||
| Tax impact of fresh start adjustments | 19.4 | ||||
| $ | (9,175.2) | ||||
(x) Accumulated other comprehensive loss
Reflects the fresh start adjustments for the elimination of Predecessor accumulated other comprehensive loss through Reorganization items, net.
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4. REVENUE FROM CONTRACTS WITH CUSTOMERS
Our drilling contracts with customers provide a drilling rig and 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 generally 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 drilling contracts contain a lease component and we have elected to apply the practical expedient provided under Accounting Standards Codification ("ASC") 842 to not separate the lease and non-lease components and apply the revenue recognition guidance in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)." Our drilling service provided under each drilling contract is a single performance obligation satisfied over time and comprised of a series of distinct time increments, or service periods. Total revenue is determined for each individual drilling contract by estimating both fixed and variable consideration expected to be earned over the contract term. Fixed consideration generally relates to activities such as mobilization, demobilization and capital upgrades of our rigs that are not distinct performance obligations within the context of our contracts and is recognized on a straight-line basis over the contract term. Variable consideration generally relates to distinct service periods during the contract term and is recognized in the period when the services are performed.
The amount estimated for variable consideration is only recognized as revenue to the extent that it is probable that a significant reversal will not occur during the contract term. We have applied the optional exemption afforded in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," and have not disclosed the variable consideration related to our estimated future day rate revenues. The remaining duration of our drilling contracts based on those in place as of December 31, 2022 (Successor) was between approximately 1 month and 5 years.
Day Rate Drilling Revenue
Our drilling contracts provide for payment on a day rate basis and include a rate schedule with higher rates for periods when the drilling rig is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The day rate invoiced to the customer is determined based on the varying rates applicable to specific activities performed on an hourly or other time increment basis. Day rate consideration is allocated to the distinct hourly or other time increment to which it relates within the contract term and is generally recognized consistent with the contractual rate invoiced for the services provided during the respective period. Invoices are typically issued to our customers on a monthly basis and payment terms on customer invoices are typically 30 days.
Certain of our contracts contain performance incentives whereby we may earn a bonus based on pre-established performance criteria. Such incentives are generally based on our performance over individual monthly time periods or individual wells. Consideration related to performance bonus is generally recognized in the specific time period to which the performance criteria was attributed.
We may receive termination fees if certain drilling contracts are terminated by the customer prior to the end of the contractual term. Such compensation is recognized as revenue when our performance obligation is satisfied, the termination fee can be reasonably measured and collection is probable.
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Contract Termination - VALARIS DS-11
In July 2021, a contract was awarded to VALARIS DS-11 for an eight-well deepwater project in the U.S. Gulf of Mexico that was expected to commence in mid-2024. In June 2022, the customer terminated the contract. As a result of the contract termination, we received an early termination fee of $51.0 million which is included in revenues on our Consolidated Statements of Operations for the year ended December 31, 2022 (Successor).
As of the date of the termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract. Costs incurred for capital upgrades specific to the customer requirements were considered to be impaired and as such, we recorded a pre-tax, non-cash loss on impairment in the second quarter of 2022 of $34.5 million See "Note 7 - Property and Equipment" for additional information on the impairment. Additional costs were recorded for penalties and other costs incurred upon cancellation of equipment ordered.
Mobilization / Demobilization Revenue
In connection with certain contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in Operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in Contract drilling expense.
Mobilization fees received prior to commencement of drilling operations are recorded as a contract liability and amortized on a straight-line basis over the contract term. Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. In some cases, demobilization fees may be contingent upon the occurrence or non-occurrence of a future event. In such cases, this may result in cumulative-effect adjustments to demobilization revenues upon changes in our estimates of future events during the contract term.
Capital Upgrade / Contract Preparation Revenue
In connection with certain contracts, we receive lump-sum fees or similar compensation generally for requested capital upgrades to our drilling rigs or for other contract preparation work. Fees received for requested capital upgrades and other contract preparation work are recorded as a contract liability and amortized on a straight-line basis over the contract term to Operating revenues.
Revenues Related to Reimbursable Expenses
We generally receive reimbursements from our customers for purchases of supplies, equipment, personnel services and other services provided at their request. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is recognized during the period in which the corresponding goods and services are consumed once the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer within Operating revenues.
Contract Assets and Liabilities
Contract assets represent amounts recognized as revenue but for which the right to invoice the customer is dependent upon our future performance. Once the previously recognized revenue is invoiced, the corresponding contract asset, or a portion thereof, is transferred to accounts receivable.
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Contract liabilities generally represent fees received for mobilization, capital upgrades or in the case of our 50/50 unconsolidated joint venture with Saudi Aramco, represent the difference between the amounts billed under the bareboat charter arrangements and lease revenues earned. See “Note 5 – Equity Method Investment in ARO" for additional details regarding our balances with ARO.
Contract assets and liabilities are presented net on our Consolidated Balance Sheets on a contract-by-contract basis. Current contract assets and liabilities are included in Other current assets and Accrued liabilities and other, respectively, and noncurrent contract assets and liabilities are included in Other assets and Other liabilities, respectively, on our Consolidated Balance Sheets.
The following table summarizes our contract assets and contract liabilities (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Current contract assets | $ | 4.6 | $ | 0.3 | |||||||
| Noncurrent contract assets | $ | 0.7 | $ | — | |||||||
| Current contract liabilities (deferred revenue) | $ | 78.0 | $ | 45.8 | |||||||
| Noncurrent contract liabilities (deferred revenue) | $ | 41.0 | $ | 10.8 | |||||||
Changes in contract assets and liabilities during the period are as follows (in millions):
| Contract Assets | Contract Liabilities | ||||||||||
| Balance as of December 31, 2020 (Predecessor) | $ | 1.8 | $ | 71.9 | |||||||
| Revenue recognized in advance of right to bill customer | 2.3 | — | |||||||||
| Increase due to cash received | — | 10.2 | |||||||||
| Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance | — | (14.8) | |||||||||
| Decrease due to transfer to receivables during the period | (1.6) | — | |||||||||
| Fresh start accounting revaluation | (0.3) | (31.6) | |||||||||
| Balance as of April 30, 2021 (Predecessor) | 2.2 | 35.7 | |||||||||
| Balance as of May 1, 2021 (Successor) | 2.2 | 35.7 | |||||||||
| Revenue recognized in advance of right to bill customer | 2.5 | — | |||||||||
| Increase due to cash received | — | 80.1 | |||||||||
| Decrease due to amortization of deferred revenue that was added during the period | — | (21.5) | |||||||||
| Decrease due to transfer to receivables and payables during the period | (4.4) | (37.7) | |||||||||
| Balance as of December 31, 2021 (Successor) | 0.3 | 56.6 | |||||||||
| Balance as of January 1, 2022 (Successor) | 0.3 | 56.6 | |||||||||
| Revenue recognized in advance of right to bill customer | 9.2 | — | |||||||||
| Increase due to cash received | — | 156.7 | |||||||||
| Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance | — | (41.1) | |||||||||
| Decrease due to amortization of deferred revenue added during the period | — | (47.1) | |||||||||
| Decrease due to transfer to receivables and payables during the period | (4.2) | (6.1) | |||||||||
| Balance as of December 31, 2022 (Successor) | $ | 5.3 | $ | 119.0 | |||||||
Deferred Contract Costs
Costs incurred for upfront rig mobilizations and certain contract preparations are attributable to our future performance obligation under each respective drilling contract. These costs are deferred and amortized on a straight-line basis over the contract term. Demobilization costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are
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expensed as incurred. Deferred contract costs were included in Other current assets and Other assets on our Consolidated Balance Sheets and totaled $57.3 million and $31.4 million as of December 31, 2022 and 2021 (Successor), respectively. For the Successor, during the year ended December 31, 2022 and the eight months ended December 31, 2021, amortization of such costs totaled $61.7 million and $22.0 million, respectively. For the Predecessor, during the four months ended April 30, 2021 and the year ended December 31, 2020, amortization of such costs totaled $7.6 million and $42.1 million, respectively.
Deferred Certification Costs
We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized on a straight-line basis over the corresponding certification periods. Deferred regulatory certification and compliance costs were included in Other current assets and Other assets on our Consolidated Balance Sheets and totaled $16.2 million and $3.3 million as of December 31, 2022 and 2021 (Successor), respectively. For the Successor, during the year ended December 31, 2022 and the eight months ended December 31, 2021, amortization of such costs totaled $4.7 million and $0.7 million, respectively. For the Predecessor, during the four months ended April 30, 2021 and the year ended December 31, 2020, amortization of these costs totaled $3.1 million and $8.9 million, respectively.
Future Amortization of Contract Liabilities and Deferred Costs
Our contract liabilities and deferred costs are amortized on a straight-line basis over the contract term or corresponding certification period to Operating revenues and Contract drilling expense, respectively, with the exception of the contract liabilities related to our bareboat charter arrangements with ARO which would not be contractually payable until the end of the lease term or termination, if sooner. See "Note 5 - Equity Method Investment in ARO" for additional information on ARO and related arrangements. The table below reflects the expected future amortization of our contract liabilities and deferred costs recorded as of December 31, 2022 (Successor). In the case of our contract liabilities related to our bareboat charter arrangements with ARO, the contract liability is not amortized and as such, the amount is reflected in the table below at the end of the current lease term.
| (In millions) | ||||||||||||||||||||||||||||||||
| 2023 | 2024 | 2025 | 2026 & Thereafter | Total | ||||||||||||||||||||||||||||
| Amortization of contract liabilities | $ | 78.0 | $ | 40.1 | $ | 0.9 | $ | — | $ | 119.0 | ||||||||||||||||||||||
| Amortization of deferred costs | $ | 59.1 | $ | 13.7 | $ | 0.4 | $ | 0.3 | $ | 73.5 | ||||||||||||||||||||||
5. EQUITY METHOD INVESTMENT IN ARO
Background
ARO is a 50/50 unconsolidated joint venture between the Company and Saudi Aramco that owns and operates offshore drilling rigs in Saudi Arabia. As of December 31, 2022, ARO owns seven jackup rigs, has ordered two newbuild jackup rigs and leases eight rigs from us through bareboat charter arrangements (the "Lease Agreements") whereby substantially all operating costs are incurred by ARO. At December 31, 2022, the leased rigs were operating under three-year drilling contracts, or related extensions, with Saudi Aramco. The seven rigs owned by ARO are currently operating under contracts with Saudi Aramco, each with an aggregate contract term of 15 years, provided that the rigs meet the technical and operational requirements of Saudi Aramco.
The Lease Agreements with ARO originally provided for a fixed per day bareboat charter amount over the term of the lease, calculated based on a split of projected earnings over the lease term. However, in December 2020,
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the shareholder agreement governing the joint venture (the "Shareholder Agreement") was amended (the "December Amendment") such that the per day bareboat charter amount in the associated lease agreements is subject to adjustment based on actual performance of the respective rig and that a cash payment based on actual results will be due at the end of the lease term or, if sooner, termination. The Company, as lessor, accounts for these arrangements as operating leases. The December Amendment resulted in a modification of the leases and as a result we began accounting for lease revenue using the variable rate as opposed to a fixed rental amount. Our results of operations for the year ended December 31, 2020 (Predecessor) include the impact of the lease modification on our rental revenues to reflect cumulative results through that period.
ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. While the shipyard contract contemplated delivery of these newbuild rigs in 2022, the delivery of these rigs has been delayed into 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. In connection with these plans, we have a potential obligation to fund ARO for newbuild jackup rigs. See “Note 14 Commitments and Contingencies" for additional information.
The joint venture partners agreed in the Shareholder Agreement that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. The initial contracts provided by Saudi Aramco for each of the newbuild rigs will be for an eight-year term. The day rate for the initial contracts for each newbuild rig will be determined using a pricing mechanism that targets a six-year payback period for construction costs on an EBITDA basis. The initial eight-year contracts will be followed by a minimum of another eight years of term, re-priced in three-year intervals based on a market pricing mechanism.
Upon establishment of ARO, we entered into an agreement to provide certain employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement"). Pursuant to this agreement, our seconded employees provide various services to ARO, and in return, ARO provides remuneration for those services. From time to time, we may also sell equipment or supplies to ARO. During the quarter ended June 30, 2020, almost all remaining employees seconded to ARO became employees of ARO.
Summarized Financial Information
The operating revenues of ARO presented below reflect revenues earned under drilling contracts with Saudi Aramco for the ARO-owned jackup rigs as well as the rigs leased from us.
Contract drilling expense is inclusive of the bareboat charter fees for the rigs leased from us. Cost incurred under the Secondment Agreement are included in Contract drilling expense and General and administrative, depending on the function to which the seconded employee's service related. See additional discussion below regarding these related-party transactions.
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Summarized financial information for ARO is as follows (in millions):
| Year Ended December 31, 2022 | Year Ended December 31, 2021 | Year Ended December 31, 2020 | |||||||||
| Revenues | $ | 459.5 | $ | 470.6 | $ | 549.4 | |||||
| Operating expenses | |||||||||||
| Contract drilling (exclusive of depreciation) | 341.8 | 362.3 | 388.2 | ||||||||
| Depreciation | 63.4 | 65.2 | 54.8 | ||||||||
| General and administrative | 18.7 | 17.8 | 24.2 | ||||||||
| Operating income | 35.6 | 25.3 | 82.2 | ||||||||
| Other expense, net | 11.1 | 13.4 | 26.7 | ||||||||
| Provision for income taxes | 3.8 | 7.9 | 14.2 | ||||||||
| Net income | $ | 20.7 | $ | 4.0 | $ | 41.3 | |||||
| December 31, 2022 | December 31, 2021 | |||||||
| Cash and cash equivalents | $ | 176.2 | $ | 270.8 | ||||
| Other current assets | 140.6 | 135.0 | ||||||
| Non-current assets | 818.1 | 775.8 | ||||||
| Total assets | $ | 1,134.9 | $ | 1,181.6 | ||||
| Current liabilities | $ | 86.3 | $ | 79.9 | ||||
| Non-current liabilities | 884.6 | 956.7 | ||||||
| Total liabilities | $ | 970.9 | $ | 1,036.6 | ||||
Equity in Earnings of ARO
We account for our interest in ARO using the equity method of accounting and only recognize our portion of ARO's net income, adjusted for basis differences as discussed below, which is included in Equity in earnings (losses) of ARO in our Consolidated Statements of Operations. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Judgments regarding our level of influence over ARO included considering key factors such as each partner's ownership interest, representation on the board of managers of ARO and ability to direct activities that most significantly impact ARO's economic performance, including the ability to influence policy-making decisions. Our investment in ARO would be assessed for impairment if there are changes in facts and circumstances that indicate a loss in value may have occurred. If a loss were deemed to have occurred and this loss was determined to be other than temporary, the carrying value of our investment would be written down to fair value and an impairment recorded.
We have an equity method investment in ARO that was recorded at its estimated fair value at both the Effective Date and the date of our 2019 transaction where we acquired the subsidiary that held the joint venture interest. We computed the difference between the fair value of ARO's net assets and the carrying value of those net assets in ARO's U.S. GAAP financial statements ("basis differences") on each of these dates. These basis differences primarily related to ARO's long-lived assets and the recognition of intangible assets associated with certain of ARO's drilling contracts that were determined to have favorable terms as of the measurement dates.
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Basis differences are amortized over the remaining life of the assets or liabilities to which they relate and are recognized as an adjustment to the Equity in earnings (losses) of ARO in our Consolidated Statements of Operations. The amortization of those basis differences is combined with our 50% interest in ARO's net income. A reconciliation of those components is presented below (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| 50% interest in ARO net income (loss) | $ | 10.4 | $ | (4.0) | $ | 6.0 | $ | 20.7 | ||||||||||||||||||
| Amortization of basis differences | 14.1 | 10.1 | (2.9) | (28.5) | ||||||||||||||||||||||
| Equity in earnings (losses) of ARO | $ | 24.5 | $ | 6.1 | $ | 3.1 | $ | (7.8) | ||||||||||||||||||
Related-Party Transactions
Revenues recognized by us related to the Lease Agreements and Secondment Agreement are as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Lease revenue | $ | 56.7 | $ | 35.4 | $ | 21.7 | $ | 52.2 | ||||||||||||||||||
| Secondment revenue | 2.0 | 1.5 | 1.1 | 21.6 | ||||||||||||||||||||||
Total revenue from ARO (1) | $ | 58.7 | $ | 36.9 | $ | 22.8 | $ | 73.8 | ||||||||||||||||||
(1) All of the revenues presented above are included in our Other segment in our segment disclosures. See "Note 16- Segment Information" for additional information.
Amounts receivable from ARO related to the Lease Agreements totaled $12.0 million and $12.1 million as of December 31, 2022 and 2021, respectively, and are included in Accounts receivable, net, on our Consolidated Balance Sheets.
We had $16.7 million and $43.2 million of Contract liabilities and Accounts payable, respectively, related to the Lease Agreements as of December 31, 2022. As of December 31, 2021, we had $10.8 million and $38.3 million of Contract liabilities and Accounts payable, respectively, related to the Lease Agreements. The per day bareboat charter amount in the Lease Agreements is subject to adjustment based on actual performance of the respective rig and as such contract liabilities related to the Lease Agreements are subject to adjustment during the lease term. Upon completion of the lease term, such amount becomes a payable to or a receivable from ARO.
During 2017 and 2018, the Company contributed cash to ARO in exchange for the 10-year Notes Receivable from ARO based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. The Shareholder Agreement prohibits the sale or transfer of the Notes Receivable from ARO to a third party, except in certain limited circumstances.
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The principal amount and discount of the Notes Receivable from ARO were as follows (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Principal amount | $ | 402.7 | $ | 442.7 | |||||||
| Discount | (148.7) | (193.6) | |||||||||
| Carrying value | $ | 254.0 | $ | 249.1 | |||||||
We collected our 2022 and 2021 interest on the Notes Receivable from ARO from ARO in cash prior to December 31, 2022 and 2021, respectively, and as such, there was no interest receivable for the Notes Receivable from ARO as of December 31, 2022 and 2021.
In September 2022, the Company received a principal payment of $40.0 million from ARO representing a partial early repayment of the Notes Receivable from ARO. In connection with this repayment, we recognized non-cash interest income of $14.8 million in the third quarter of 2022 for the discount attributable to this repayment. Non-cash interest income from the Notes Receivable from ARO is included in Interest income in our Consolidated Statement of Operations.
Interest income earned on the Notes Receivable from ARO was as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Interest income | $ | 11.3 | $ | 7.0 | $ | 3.5 | $ | 18.3 | ||||||||||||||||||
| Non-cash amortization | 44.9 | 20.8 | — | — | ||||||||||||||||||||||
Total interest income on the Notes Receivable from ARO | $ | 56.2 | $ | 27.8 | $ | 3.5 | $ | 18.3 | ||||||||||||||||||
Maximum Exposure to Loss
The following table summarizes the total assets and liabilities as reflected in our Consolidated Balance Sheets as well as our maximum exposure to loss related to ARO (in millions). Our maximum exposure to loss is limited to (1) our equity investment in ARO; (2) the carrying amount of our Notes Receivable from ARO; and (3) other receivables and contract assets from ARO, partially offset by contract liabilities as well as payables to ARO.
| December 31, 2022 | December 31, 2021 | ||||||||||
| Total assets | $ | 377.8 | $ | 348.1 | |||||||
| Less: total liabilities | 59.9 | 49.1 | |||||||||
| Maximum exposure to loss | $ | 317.9 | $ | 299.0 | |||||||
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6. FAIR VALUE MEASUREMENTS
The carrying values and estimated fair values of certain of our financial instruments were as follows (in millions):
| December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||
| Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | |||||||||||||||||||||||
First Lien Notes(1) | $ | 542.4 | $ | 545.9 | $ | 545.3 | $ | 575.7 | ||||||||||||||||||
Long-term notes receivable from ARO (2) | $ | 254.0 | $ | 336.7 | $ | 249.1 | $ | 266.7 | ||||||||||||||||||
(1)The estimated fair value of the First Lien Notes was determined using quoted market prices, which are level 1 inputs.
(2)The estimated fair value of our Notes Receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the Notes Receivable from ARO using a discount rate based on a comparable yield with a country-specific risk premium, which are considered to be level 2 inputs.
The estimated fair values of our cash and cash equivalents, restricted cash, accounts receivable and trade payables approximated their carrying values as of December 31, 2022 and 2021 (Successor).
7. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following (in millions):
| December 31, 2022 | December 31, 2021 | |||||||||||||
| Drilling rigs and equipment | $ | 1,036.5 | $ | 886.9 | ||||||||||
| Work-in-progress | 59.8 | 35.6 | ||||||||||||
| Other | 38.2 | 34.5 | ||||||||||||
| $ | 1,134.5 | $ | 957.0 | |||||||||||
Assets held-for-use
On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable. For rigs whose carrying values are determined not to be recoverable, we record an impairment for the difference between their fair values and carrying values.
Successor
In June 2022, the drilling contract previously awarded to VALARIS DS-11 was terminated. As of the date of termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract. Costs incurred related to these capital upgrades were included in work-in-progress and upon termination were determined to be impaired. We recorded a pre-tax, non-cash loss on impairment in the second quarter of 2022 of $34.5 million. See "Note 4 - Revenue from Contracts with Customers" for additional information regarding the termination.
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Predecessor
During the first quarter of 2021, as a result of challenging market conditions for certain of our floaters, we revised our near-term operating assumptions which resulted in a triggering event for purposes of evaluating impairment. We determined that the estimated undiscounted cash flows were not sufficient to recover the carrying values for certain rigs and concluded they were impaired as of March 31, 2021.
Based on the asset impairment analysis performed as of March 31, 2021, we recorded a pre-tax, non-cash loss on impairment in the first quarter of 2021 for certain floaters totaling $756.5 million, inclusive of $5.6 million of gains reclassified from accumulated other comprehensive income into loss on impairment associated with related cash flow hedges. We measured the fair value of these assets to be $26.0 million at the time of impairment by applying either an income approach, using projected discounted cash flows, or estimated sales price. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including, in the case of an income approach, assumptions regarding future day rates, utilization, operating costs and capital requirements. In instances where we applied an income approach, forecasted day rates and utilization took into account then current market conditions and our anticipated business outlook.
During the first quarter of 2020, the COVID-19 global pandemic and the response thereto negatively impacted the macro-economic environment and global economy. Global oil demand fell sharply at the same time global oil supply increased as a result of certain oil producers competing for market share which lead to a supply glut. As a consequence, Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel as of mid-April 2020. These adverse changes and impacts to our customer's capital expenditure plans in the first quarter resulted in further deterioration in our forecasted day rates and utilization for the remainder of 2020 and beyond. As a result, we concluded that a triggering event had occurred, and we performed a fleet-wide recoverability test. We determined that our estimated undiscounted cash flows were not sufficient to recover the carrying values of certain rigs and concluded they were impaired as of March 31, 2020.
Based on the asset impairment analysis performed as of March 31, 2020, we recorded a pre-tax, non-cash loss on impairment in the first quarter with respect to certain floaters, jackups and spare equipment totaling $2.8 billion. We measured the fair value of these assets to be $72.3 million at the time of impairment by applying either an income approach, using projected discounted cash flows, or estimated sales price. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including, in the case of an income approach, assumptions regarding future day rates, utilization, operating costs and capital requirements. In instances where we applied an income approach, forecasted day rates and utilization took into account then current market conditions and our anticipated business outlook at that time, both of which had been impacted by the adverse changes in the business environment observed during the first quarter of 2020.
During the second quarter of 2020, given the anticipated sustained market impacts arising from the decline in oil price and demand late in the first quarter, we revised our long-term operating assumptions which resulted in a triggering event for purposes of evaluating impairment and we performed a fleet-wide recoverability test. As a result, we recorded a pre-tax, non-cash impairment with respect to two floaters and spare equipment totaling $817.3 million. We measured the fair value of these assets to be $69.0 million at the time of impairment by applying an income approach or estimated scrap value. These valuations were based on unobservable inputs that require significant judgments for which there is limited information including, in the case of the income approach, assumptions regarding future day rates, utilization, operating costs and capital requirements.
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Assets held-for-sale and Assets sold
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. 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 Indenture dated April 30, 2021 that governs our First Lien Notes (the “Indenture”), 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. To this end, we continually assess our rig portfolio and actively work with rig brokers to market certain rigs. See “Note 8 – Debt" for additional information on restrictions on the sales of assets.
On a quarterly basis, we assess whether any long-lived assets meet the criteria established for held-for-sale classification on our balance sheet. Assets classified as held-for-sale are recorded at fair value, less costs to sell. We measure the fair value of our assets held-for-sale by applying a market approach based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants or a negotiated sales price. We reassess the fair value of our held-for-sale assets on a quarterly basis and adjust the carrying value, as necessary. Any gains recognized on sales of assets are included in Other, net on the Consolidated Statements of Operations. No assets were classified as held-for-sale on our Consolidated Balance Sheet as of December 31, 2022 (Successor) and December 31, 2021 (Successor).
Successor
During the year ended December 31, 2022 (Successor), we recognized an aggregate pre-tax gain of $130.5 million for the sales of VALARIS 113, VALARIS 114, VALARIS 36 and VALARIS 67. Additionally, we recognized pre-tax gains of $3.2 million and $7.0 million related to additional proceeds received for our 2021 sale of VALARIS 100 and 2020 sale of VALARIS 68, respectively, resulting from post-sale conditions of those sale agreements.
In September 2022, we reached an agreement to sell VALARIS 54 to a third party, the closing of which is subject to customary closing conditions, after completion of its current contract in March 2023. We expect to recognize a pre-tax gain on the sale of approximately $28 million during the first half of 2023.
During the eight months ended December 31, 2021, we sold VALARIS 22, VALARIS 37, VALARIS 100 and VALARIS 142, resulting in a pre-tax gain of $20.7 million.
Predecessor
In April 2021, we sold VALARIS 101 resulting in a pre-tax gain of $5.3 million. In March 2021, we sold our Australia office building resulting in an insignificant pre-tax gain.
During the second quarter of 2020, we classified the following rigs as held-for-sale: VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS DS-3, VALARIS DS-5, VALARIS DS-6 and VALARIS 105. The carrying value of certain of these rigs was reduced to fair value, less costs to sell, based on their estimated sales price, and we recorded a pre-tax, non-cash loss on impairment totaling $15.0 million. These rigs were subsequently sold during the third quarter of 2020 for an aggregate pre-tax gain of $8.6 million. During the third quarter of 2020, we classified VALARIS 8504, VALARIS 84 and VALARIS 88 as held-for-sale. The fair value, less costs to sell, based on each rig's estimated sales price, was in excess of the respective carrying value. As a result, we concluded that there was no impairment of these rigs. These rigs were sold during the fourth quarter of 2020 for an aggregate pre-tax gain of $2.7 million.
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8. DEBT
First Lien Notes Indenture
On the Effective Date, in accordance with the plan of reorganization and Backstop Commitment Agreement, dated August 18, 2020 (as amended, the "BCA"), the Company consummated the rights offering of the First Lien Notes and associated Common Shares in an aggregate principal amount of $550.0 million. In accordance with the BCA, certain holders of senior notes claims and certain holders of claims under the Revolving Credit Facility who provided backstop commitments received the backstop premium in an aggregate amount equal to $50.0 million in First Lien Notes and 2.7% of the Common Shares on the Effective Date. The Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date, which was loaned back to the reorganized company upon emergence. Therefore, upon emergence the Debtors received $520.0 million in cash in exchange for a $550.0 million note, which includes the backstop premium. See “Note 2 – Chapter 11 Proceedings” for additional information.
The First Lien Notes were issued pursuant to the Indenture, among Valaris Limited, certain direct and indirect subsidiaries of Valaris Limited as guarantors, and Wilmington Savings Fund Society, FSB, as collateral agent and trustee (in such capacities, the “Collateral Agent”).
The First Lien Notes are guaranteed, jointly and severally, on a senior basis, by certain of the direct and indirect subsidiaries of the Company. The First Lien Notes and such guarantees are secured by first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by the Company or any guarantor and a first-priority perfected lien on substantially all assets of the Company and each guarantor of the First Lien Notes, in each case subject to certain exceptions and limitations. The following is a brief description of the material provisions of the Indenture and the First Lien Notes.
The First Lien Notes are scheduled to mature on April 30, 2028. Interest on the First Lien Notes accrues, at our option, at a rate of: (1) 8.25% per annum, payable in cash; (2) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (3) 12% per annum, with the entirety of such interest to be paid in kind. Interest is due semi-annually in arrears on May 1 and November 1 of each year and shall be computed on the basis of a 360-day year of twelve 30-day months.
At any time prior to April 30, 2023, the Company may redeem up to 35% of the aggregate principal amount of the First Lien Notes at a redemption price of 104% up to the net cash proceeds received by the Company from equity offerings provided that at least 65% of the aggregate principal amount of the First Lien Notes remains outstanding and provided that the redemption occurs within 120 days after such equity offering of the Company. At any time prior to April 30, 2023, the Company may redeem the First Lien Notes at a redemption price of 104% of the principal amount plus a “make-whole” premium. On or after April 30, 2023, the Company may redeem all or part of the First Lien Notes at fixed redemption prices (which are expressed as percentages of the principal amount) beginning at 104% on April 30, 2023 and declining each 12-month period thereafter to 100% on and after April 30, 2026, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Notwithstanding the foregoing, if a Change of Control (as defined in the Indenture, with certain exclusions as provided therein) occurs, the Company will be required to make an offer to repurchase all or any part of each note holder’s notes at a purchase price equal to 101% of the aggregate principal amount of First Lien Notes repurchased, plus accrued and unpaid interest to, but excluding, the applicable date.
The Indenture contains covenants that limit, among other things, the Company’s ability and the ability of the guarantors and other restricted subsidiaries, to: (1) incur, assume or guarantee additional indebtedness; (2) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (3) make investments; (4) repay or redeem junior debt; (5) transfer or sell assets; (6) enter into sale and lease back transactions; (7) create, incur or assume liens; and (8) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions. As of December 31, 2022 (Successor), we were in compliance with our covenants under the Indenture.
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The Indenture also provides for certain customary events of default, including, among other things, nonpayment of principal or interest, breach of covenants, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a collateral document to create an effective security interest in collateral, with a fair market value in excess of a specified threshold, bankruptcy and insolvency events, cross payment default and cross acceleration, which could permit the principal, premium, if any, interest and other monetary obligations on all the then outstanding First Lien Notes to be declared due and payable immediately.
The Company incurred $5.2 million in issuance costs in 2021 associated with the First Lien Notes. Also, in August 2022, the Company completed a consent solicitation pursuant to which the Company amended the Indenture to (1) implement a consolidated net income builder basket for restricted payments, increase the general basket for restricted payments from $100.0 million to $175.0 million and make other incremental changes to the Company’s restricted payments capacity and (2) increase the general basket for investments from the greater of $100.0 million and 4.0% of total assets to the greater of $175.0 million and 6.5% of total assets. The Company incurred $3.9 million of costs in connection with the consent solicitation, comprised of a consent fee paid to consenting holders and professional fees. These costs along with the issuance costs incurred in 2021 are being amortized into interest expense over the expected term of the First Lien Notes using the effective interest method.
Predecessor Debtor in Possession Financing
On September 25, 2020, following approval by the Bankruptcy Court, the Debtors entered into the Debtor-in-Possession ("DIP") Credit Agreement (the "DIP Credit Agreement"), by and among the Company and certain wholly owned subsidiaries of the Company, as borrowers, the lenders party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and security trustee, in an aggregate amount not to exceed $500.0 million to finance, among other things, the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases and to pay certain fees, costs and expenses associated with the Chapter 11 Cases. As of the Effective Date, there were no borrowings outstanding against our DIP facility and there were no DIP claims payable subsequent to, or that otherwise survived, the Effective Date. The DIP Credit Agreement terminated on the Effective Date.
Predecessor Senior Notes
The commencement of the Chapter 11 Cases was considered an event of default under our Senior Notes and all obligations thereunder were accelerated. However, any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed as a result of the filing of the Chapter 11 Cases. Accordingly, the $6.5 billion in aggregate principal amount outstanding under the Senior Notes as well as $201.9 million in associated accrued interest as of the Petition Date were classified as Liabilities Subject to Compromise in our Consolidated Balance Sheets as of December 31, 2020 (Predecessor). On the Effective Date, pursuant to the plan of reorganization, our Senior Notes were cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization.
Predecessor Revolving Credit Facility
The commencement of the Chapter 11 Cases resulted in an event of default under our Revolving Credit Facility. However, the ability of the lenders to exercise remedies in respect of the Revolving Credit Facility was stayed upon commencement of the Chapter 11 Cases. Accordingly, the $581.0 million of outstanding borrowing as well as accrued interest as of the Petition Date were classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). On the Effective Date, pursuant to the plan of reorganization, the Revolving Credit Facility was cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization.
Prior to the Effective Date, pursuant to the plan of reorganization, all undrawn letters of credit issued under the Revolving Credit Facility were collateralized pursuant to the terms of the Revolving Credit Facility.
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Predecessor Tender Offers and Open Market Repurchases
In March 2020, we repurchased $12.8 million of our outstanding senior notes due 2021 on the open market for an aggregate purchase price of $9.7 million, excluding accrued interest, with cash on hand. As a result of the transaction, we recognized a pre-tax gain of $3.1 million, net of discounts in Other, net, in the Consolidated Statements of Operations.
Interest Expense
Interest expense totaled $45.3 million for the year ended December 31, 2022 (Successor) which was net of capitalized interest of $1.2 million for capital projects. Interest expense totaled $31.0 million and $2.4 million for the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), respectively. Interest expense totaled $290.6 million for the year ended December 31, 2020 (Predecessor) which was net of capitalized interest of $1.3 million associated with newbuild rig construction and other capital projects. The contractual interest expense on the outstanding Senior Notes and the Revolving Credit Facility was in excess of recorded interest expense by $132.9 million and $140.7 million for the four months ended April 30, 2021 (Predecessor) and for the year ended December 31, 2020 (Predecessor), respectively. This excess contractual interest was not included as interest expense on our Consolidated Statements of Operations, as the Company discontinued accruing interest on the unsecured senior notes and Revolving Credit Facility subsequent to the Petition Date. We discontinued making interest payments on our unsecured senior notes beginning in June 2020.
Amortization of debt discount and issuance costs was $1.0 million, $0.5 million and $36.8 million for year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor) and the year ended December 31, 2020 (Predecessor), respectively. Additionally, we incurred an aggregate net non-cash charge of $447.9 million for the year ended December 31, 2020 (Predecessor) to write off unamortized debt discounts, premiums and issuance costs associated with our Senior Notes and Revolving Credit Facility, which is included in Reorganization items, net on our Consolidated Statements of Operations.
9. DERIVATIVE INSTRUMENTS
Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues 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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. We previously used derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk.
The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permitted the counterparties of our derivative instruments to terminate their outstanding contracts. The exercise of these termination rights are not stayed under the Bankruptcy Code and the counterparties elected to terminate their outstanding derivatives with us in September 2020 for an aggregate settlement of $3.6 million which was recorded as a gain in Contract drilling expense in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor). During the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), we did not enter into derivative contracts; therefore, we do not have derivative assets or liabilities on our Consolidated Balance Sheets as of December 31, 2022 (Successor) or December 31, 2021 (Successor).
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Historically, we utilized cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with contract drilling expenses and capital expenditures denominated in various currencies. Gains and losses, net of tax, on derivatives designated as cash flow hedges included in our Consolidated Statements of Operations and comprehensive loss were as follows (in millions):
| Foreign Currency Forward Contracts | ||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||
| Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | ||||||||||||||||||
| Loss recognized in Other Comprehensive Income ("OCI") on Derivatives (Effective Portion) | $ | — | $ | — | $ | (5.4) | ||||||||||||||
Gain reclassified from AOCI into income (Effective Portion) (1) | $ | — | $ | (5.6) | $ | (11.6) | ||||||||||||||
(1)During the four months ended April 30, 2021 (Predecessor), $5.6 million of gains were reclassified from AOCI into in our Consolidated Statements of Operations in connection with the impairment of certain rigs. During the year ended December 31, 2020 (Predecessor), $2.0 million of losses were reclassified from AOCI into Contract drilling expense and $13.6 million of gains were reclassified from AOCI into Depreciation expense in our Consolidated Statements of Operations.
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10. SHAREHOLDERS' EQUITY
Activity in our various shareholders' equity accounts for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor) were as follows (in millions):
| Shares | Par Value | Additional Paid-in Capital | Warrants | Retained Earnings (Deficit) | AOCI | Treasury Shares | Non-controlling Interest | ||||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2019 (Predecessor) | 205.9 | $ | 82.5 | $ | 8,627.8 | $ | — | $ | 671.7 | $ | 6.2 | $ | (77.3) | $ | (1.3) | ||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | (4,855.5) | — | — | (2.1) | |||||||||||||||||||||||||||||||||||||||
| Net changes in pension and other postretirement benefits | — | — | — | — | — | (76.5) | — | — | |||||||||||||||||||||||||||||||||||||||
| Purchase of noncontrolling interests | — | — | (7.2) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (0.9) | |||||||||||||||||||||||||||||||||||||||
| Shares issued under share-based compensation plans, net | 0.2 | 0.1 | (1.9) | — | — | — | 2.0 | — | |||||||||||||||||||||||||||||||||||||||
| Repurchase of shares | — | — | — | — | — | — | (0.9) | — | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation cost | — | — | 21.2 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Net other comprehensive loss | — | — | — | — | — | (17.6) | — | — | |||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2020 (Predecessor) | 206.1 | 82.6 | 8,639.9 | — | (4,183.8) | (87.9) | (76.2) | (4.3) | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | (4,467.0) | — | — | 3.2 | |||||||||||||||||||||||||||||||||||||||
| Shares issued under share-based compensation plans, net | — | — | (0.7) | — | — | — | 0.7 | — | |||||||||||||||||||||||||||||||||||||||
| Net changes in pension and other postretirement benefits | — | — | — | — | — | 0.1 | — | — | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation cost | — | — | 4.8 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Net other comprehensive loss | — | — | — | — | — | (5.6) | — | — | |||||||||||||||||||||||||||||||||||||||
| Cancellation of Predecessor equity | (206.1) | (82.6) | (8,644.0) | — | 8,650.8 | 93.4 | 75.5 | — | |||||||||||||||||||||||||||||||||||||||
| Issuance of Successor Common Shares and Warrants | 75.0 | 0.8 | 1,078.7 | 16.4 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| BALANCE, April 30, 2021 (Predecessor) | 75.0 | 0.8 | 1,078.7 | 16.4 | — | — | — | (1.1) | |||||||||||||||||||||||||||||||||||||||
| BALANCE, May 1, 2021 (Successor) | 75.0 | 0.8 | 1,078.7 | 16.4 | — | — | — | (1.1) | |||||||||||||||||||||||||||||||||||||||
| Adjustment to unrecognized tax benefits | — | — | — | — | 11.0 | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | (27.4) | — | — | 3.8 | |||||||||||||||||||||||||||||||||||||||
| Net changes in pension and other postretirement benefits | — | — | — | — | — | (9.1) | — | — | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation cost | — | — | 4.3 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2021 (Successor) | 75.0 | 0.8 | 1,083.0 | 16.4 | (16.4) | (9.1) | — | 2.7 | |||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 176.5 | — | — | 5.3 | |||||||||||||||||||||||||||||||||||||||
| Share-based compensation cost | — | — | 17.4 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Shares issued under share-based compensation plans, net | 0.2 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Net changes in pension and other postretirement benefits | — | — | — | — | — | 23.8 | — | — | |||||||||||||||||||||||||||||||||||||||
| Shares withheld for taxes on vesting of share-based awards | — | — | (2.5) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| BALANCE, December 31, 2022 (Successor) | 75.2 | $ | 0.8 | $ | 1,097.9 | $ | 16.4 | $ | 160.1 | $ | 14.7 | $ | — | $ | 8.0 | ||||||||||||||||||||||||||||||||
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Valaris Limited Share Capital
As of the Effective Date, the authorized share capital of Valaris Limited is $8.5 million divided into 700.0 million Common Shares of a par value of $0.01 each and 150.0 million preference shares of a par value of $0.01.
Issuance of Common Shares
On the Effective Date, pursuant to the plan of reorganization, we issued 75.0 million Common Shares.
Cancellation of Predecessor Equity and Issuance of Warrants
On the Effective Date and pursuant to the plan of reorganization, the Legacy Valaris Class A ordinary shares were cancelled and the Company issued 5.6 million Warrants to the former holders of the Company's equity interests outstanding prior to the Effective Date. The Warrants are exercisable for one Common Share per Warrant at an initial exercise price of $131.88 per Warrant, in each case as may be adjusted from time to time pursuant to the applicable warrant agreement. The Warrants are exercisable for a period of seven years and will expire on April 29, 2028. The exercise of these Warrants into Common Shares would have a dilutive effect to the holdings of Valaris Limited's existing shareholders.
Management Incentive Plan
In accordance with the plan of reorganization, Valaris Limited adopted the MIP as of the Effective Date and authorized and reserved 9.0 million Common Shares for issuance pursuant to equity incentive awards to be granted under the MIP. See "Note 11 - Share Based Compensation" for information on equity awards granted under the MIP subsequent to the Effective Date.
Share Repurchase Program
In September 2022, our board of directors authorized a share repurchase program under which we may purchase up to $100.0 million of our outstanding Common Shares. The share repurchase program does not have a fixed expiration, and may be modified, suspended or discontinued at any time. As of December 31, 2022 (Successor), there have been no share repurchases under this repurchase program.
11. SHARE BASED COMPENSATION
On the Effective Date and pursuant to the plan of reorganization, all of the Predecessor's ordinary shares were cancelled. In accordance with the plan of reorganization, all agreements, instruments and other documents evidencing, relating or otherwise connected with any of Legacy Valaris' equity interests outstanding prior to the Effective Date, including all equity-based awards, were cancelled. Therefore, any Predecessor remaining long-term incentive plans were cancelled. See "Note 2 - Chapter 11 Proceedings" for additional information.
Valaris Limited adopted the MIP as of the Effective Date and authorized and reserved 9.0 million Common Shares for issuance pursuant to equity incentive awards to be granted under the MIP, which may be in the form of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and cash awards or any combination thereof. As of December 31, 2022 (Successor), there were 7.1 million shares available for issuance under the MIP.
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Non-Vested Share Awards, Cash-Settled Awards and Non-employee Director Awards
Successor Awards
Under the Company's MIP, time-based restricted stock unit awards were granted to certain employees and senior officers which vest ratably over a three-year period from the date of grant. The grant-date fair value per share for these time-based restricted stock awards was equal to the closing price of the Company's stock on the grant date. For senior officers, delivery of the shares underlying vested restricted stock awards is deferred until the third anniversary of the date of grant.
Non-employee directors received a one-time grant of time-based restricted awards upon our emergence from the Chapter 11 Cases which vest ratably over a three-year period from the date of grant. Additionally, non-employee directors received an annual grant of time-based restricted awards which vest in full on the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant. Non-employee directors are permitted to elect to receive deferred share awards which can be settled and delivered on the six-month anniversary following the termination of the director's service or a specific pre-determined date.
Our non-vested share awards do not have voting or participating rights as the dividend equivalent provided for in the award agreement is forfeitable (except in certain limited circumstances) and further our debt agreements limit our ability to pay dividends and none have been declared. Compensation expense for share awards is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Our compensation cost is reduced for forfeited awards in the period in which the forfeitures occur.
Predecessor Awards
The Predecessor granted share awards and share units (collectively "share awards") and share units to be settled in cash ("cash-settled awards"), which generally vested at a rate of 33% per year, as determined by the compensation committee of Legacy Valaris' board of directors at the time of grant. Additionally, non-employee directors were permitted to elect to receive deferred share awards. Deferred share awards vested at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant but were not to be settled until the director terminated service from the board of directors. Deferred share awards were to be settled in cash, shares or a combination thereof at the discretion of the compensation committee.
The Predecessor's non-vested share awards had voting and dividend rights effective on the date of grant, and the non-vested share units had dividend rights effective on the date of grant. Compensation expense for share awards was measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Compensation expense for cash-settled awards was remeasured each quarter with a cumulative adjustment to compensation cost during the period based on changes in the Legacy Valaris share price. Compensation cost was also reduced for forfeited awards in the period in which the forfeitures occurred.
As discussed above, in accordance with the plan of reorganization, the unvested awards of employees, senior executive officers and non-employee directors remaining on the Effective Date were cancelled for no consideration.
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The following table summarizes share award and cash-settled award compensation expense recognized (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Contract drilling | $ | 3.9 | $ | 1.6 | $ | 2.4 | $ | 10.7 | ||||||||||||||||||
| General and administrative | 6.8 | 2.0 | 2.4 | 9.2 | ||||||||||||||||||||||
| 10.7 | 3.6 | 4.8 | 19.9 | |||||||||||||||||||||||
| Tax benefit | (0.9) | (0.2) | (0.5) | (1.8) | ||||||||||||||||||||||
Total | $ | 9.8 | $ | 3.4 | $ | 4.3 | $ | 18.1 | ||||||||||||||||||
As of December 31, 2022, there was $22.0 million of total estimated unrecognized compensation cost related to Successor share awards, which has a weighted-average remaining vesting period of 1.4 years.
The following tables summarizes the value of share awards and cash-settled awards granted and vested:
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Share Awards | ||||||||||||||||||||||||||
Weighted-average grant date fair value of share awards granted (per share) (1) | $ | 45.39 | $ | 26.07 | $ | — | $ | 3.07 | ||||||||||||||||||
Total fair value of share awards vested during the period (in millions) (2) | $ | 12.8 | $ | — | $ | — | $ | 3.3 | ||||||||||||||||||
| Cash-Settled Awards | ||||||||||||||||||||||||||
Weighted-average grant date fair value of share awards granted (per share) (3) | $ | — | $ | — | $ | — | $ | 0.75 | ||||||||||||||||||
Total fair value of share awards vested during the period (in millions) (4) | $ | — | $ | — | $ | — | $ | 0.2 | ||||||||||||||||||
(1)During the four months ended April 30, 2021 (Predecessor), no share awards were granted.
(2)No share awards vested during the eight months ended December 31, 2021 (Successor). During the four months ended April 30, 2021 (Predecessor), we had an immaterial vesting of share awards.
(3)During the years ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor) and four months ended April 30, 2021 (Predecessor), no cash-settled awards were granted.
(4)During the years ended December 31, 2022 (Successor) and eight months ended December 31, 2021 (Successor), no cash-settled awards vested. During the four months ended April 30, 2021 (Predecessor), we had an immaterial vesting of cash-settled awards.
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The following table summarizes share awards activity for the year ended December 31, 2022 (Successor) (shares in thousands):
| Share Awards | |||||||||||
| Awards | Weighted-Average Grant Date Fair Value | ||||||||||
Share awards as of December 31, 2021 (Successor) | 858 | $ | 26.30 | ||||||||
| Granted | 331 | 45.39 | |||||||||
Vested(1) | (284) | 26.40 | |||||||||
| Forfeited | (44) | 25.02 | |||||||||
Share awards as of December 31, 2022 (Successor) | 861 | $ | 33.54 | ||||||||
(1) The vested share awards include 48,770 awards with a weighted average grant date fair value of $30.36 per share, for which delivery of the shares is deferred until the third anniversary of the date of grant. As of December 31, 2022, these awards had a weighted average remaining contractual life of 1.6 years and a total fair value of $3.3 million.
Performance Awards
Successor Awards
Under the Company's MIP, performance awards may be issued to our senior officers. The performance awards are allocated based on three performance goals and subject to achievement of those performance goals based on (a) designated share price hurdles whereby our closing stock price must equal or exceed certain market price targets for ninety consecutive trading days (the "Market-Based Objectives"); (b) relative return on capital employed ("ROCE") as compared to a specified peer group, all as defined in the award agreements (the "ROCE Objective"), and (c) specified strategic goals as established by a committee of the board of directors (the "Strategic Goal Objective" and together with the ROCE Objective, the "Performance-Based Objectives"). Awards are payable in equity following a three-year performance period and subject to attainment of relative Market-Based Objectives and Performance-Based Objectives ranging from 0% to 150% of target performance under such objectives.
Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. The estimated probable outcome of attainment of the specified performance goals is based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate as it relates to the Performance-Based Objectives are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs. Compensation cost for the Market-Based Objectives is recognized as long as the requisite service period is completed and will not be reversed even if the Market-Based Objectives are never satisfied. Compensation expense for performance awards is recognized over the requisite service period using the accelerated method and is reduced for forfeited awards in the period in which the forfeitures occur.
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The fair value of the performance awards granted during the year ended December 31, 2022 (Successor) and eight months ended December 31, 2021 (Successor) are measured on the date of grant. The grant-date fair value per unit for the portion of the performance awards related to Performance-Based Objectives was equal to the closing price of the Company's stock on the grant date. The portion of these awards that were based on the Company's achievement of Market-based Objectives were valued at the date of grant using a Monte Carlo simulation with the following weighted average assumptions for the grants made over the year ended December 31, 2022 (Successor) and eight months ended December 31, 2021 (Successor):
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | ||||||||||
| Expected price volatility | 61 | % | 61 | % | |||||||
| Expected dividend yield | — | — | |||||||||
| Risk-free interest rate | 3.49 | % | 0.73 | % | |||||||
The expected price volatility assumption is estimated using market data for certain peer companies during periods in which our own trading history is limited. As our trading history increases, it will bear greater weight in determining our expected price volatility assumption.
The weighted average grant-date fair value of performance awards granted during the year ended December 31, 2022 (Successor) and the eight months ended December 31, 2021 (Successor) was $38.08 and $15.93, respectively.
The following table summarizes the performance award activity for the year ended December 31, 2022 (Successor) (shares in thousands):
Awards(2) | Weighted Average Grant Date Fair Value Price(2) | ||||||||||
Balance as of December 31, 2021 (Successor) | 609 | $ | 17.53 | ||||||||
Granted - Market-Based Objectives(1) | 100 | 32.90 | |||||||||
Granted - Performance-Based Objectives(1) | 58 | 47.03 | |||||||||
| Total Granted | 158 | 38.08 | |||||||||
Balance as of December 31, 2022 (Successor) | 767 | $ | 21.77 | ||||||||
(1)The number of awards granted reflects the shares that would be granted if the target level of performance were to be achieved. The number of shares actually issued after considering forfeitures may range from zero to 236,817.
(2)There were no forfeited or vested shares for the year ended December 31, 2022 (Successor).
During the year ended December 31, 2022 (Successor) and eight months ended December 31, 2021 (Successor), we recognized of $6.7 million and $0.7 million of compensation expense for performance awards, respectively, which was included in General and administrative expense in our Consolidated Statements of Operations.
As of December 31, 2022 (Successor), there was $14.0 million of total estimated unrecognized compensation cost related to share awards, which has a weighted-average remaining vesting period of 1.6 years.
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Predecessor Awards
Under the Predecessor incentive plans, performance awards were permitted to be issued to senior officers. The 2019 performance awards were subject to achievement of specified performance goals based on both relative and absolute total shareholder return ("TSR"). The 2020 performance awards were forfeited in exchange for cash-based incentive and retention awards.
The performance goals were determined by a committee of the board of directors and the awards were payable in cash upon attainment of relative performance goals.
Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Performance awards granted during 2019 were classified as liability awards, all with compensation expense recognized over the requisite service period. The estimated probable outcome of attainment of the specified performance goals was based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate were recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurred.
The aggregate fair value of performance awards vested during 2020 (Predecessor) totaled $5.2 million.
During the year ended December 31, 2020 (Predecessor), we recognized $1.0 million of compensation expense for performance awards which was included in General and administrative expense in our Consolidated Statements of Operations. No compensation expense was recognized in connection with these awards during the four months ended April 30, 2021 (Predecessor) or the eight months ended December 31, 2021 (Successor) as per the terms of these awards, no amount could be or can be earned due to the TSR provisions of the award. While this award was not cancelled in accordance with the plan of reorganization, it has no value.
Share Appreciation Rights
Predecessor Awards
Share Appreciation Rights ("SARs") granted to employees under our Predecessor incentive plans were accounted for as equity awards. As of April 30, 2021, there were 319,641 SARs outstanding, all of which were fully vested. In accordance with the plan of reorganization, these remaining outstanding SARs were cancelled.
Share Option Awards
Predecessor Awards
As of April 30, 2021, there were fully vested options outstanding to purchase 313,377 shares under our Predecessor incentive plans. In accordance with the plan of reorganization, these outstanding options were cancelled.
12. PENSION AND OTHER POST-RETIREMENT BENEFITS
We have defined-benefit pension plans and post-retirement health and life insurance plans that provide benefits upon retirement for certain full-time employees. The defined-benefit pension plans include: (1) a pension plan which was amended in 2018 to freeze any future benefit accrual whereby eligible employees no longer receive pay credits in the plan and newly hired employees are not eligible to participate (the “Pension Plan”); (2) a legacy supplemental executive retirement plan which was also frozen in 2018 (the “Legacy SERP”); and (3) a supplemental executive retirement plan which prior to July 1, 2021, was not designated as a defined benefit plan (the “SERP”). Additionally, we have frozen retiree life and medical supplemental plans (the “Retiree Medical Plans”) which provide post-retirement health and life insurance benefits.
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The SERP is a non-qualified plan that provided eligible employees an opportunity to defer a portion of their compensation for use after retirement. The SERP was frozen to the entry of new participants in November 2019 and to future compensation deferrals as of January 1, 2020. Assets held in a rabbi trust maintained for the SERP were marketable securities which, pursuant to the plan of reorganization, were liquidated upon the Effective Date and used to satisfy the claims of creditors. Net unrealized gains of $1.2 million and $3.2 million from marketable securities held in our SERP were included in Other, net, in our Consolidated Statements of Operations for the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively.
Effective July 1, 2021, we amended the SERP to provide for quarterly credits of an interest equivalent based upon the rate of interest paid on ten-year United States treasury notes in November of the immediately preceding calendar year and the participant plan balances as of the first day of such quarter and began accounting for this plan as a defined benefit plan.
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The following table presents the changes in benefit obligations and plan assets for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) and the funded status and weighted-average assumptions used to determine the benefit obligation at the measurement date (dollars in millions):
| Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | Total | Pension Benefits | Other Benefits | Total | Pension Benefits | Other Benefits | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Projected benefit obligation: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| BALANCE at the beginning of the period | $ | 827.9 | $ | 15.6 | $ | 843.5 | $ | 826.1 | $ | 14.8 | $ | 840.9 | $ | 886.7 | $ | 15.9 | $ | 902.6 | |||||||||||||||||||||||||||||||||||||||||
| Interest cost | 22.0 | 0.4 | 22.4 | 15.3 | 0.3 | 15.6 | 6.5 | 0.1 | 6.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Actuarial loss (gain) | (191.0) | (3.8) | (194.8) | 20.6 | (4.2) | 16.4 | (55.0) | (1.0) | (56.0) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Plan settlements | (1.4) | — | (1.4) | (25.9) | — | (25.9) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Plan amendments | — | — | — | 0.2 | — | 0.2 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Benefits paid | (46.0) | (0.6) | (46.6) | (25.7) | (0.3) | (26.0) | (12.1) | (0.2) | (12.3) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Net transfer in (including the effect of any business combinations/divestitures) | — | — | — | 17.3 | 5.0 | 22.3 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| BALANCE at the end of the period | $ | 611.5 | $ | 11.6 | $ | 623.1 | $ | 827.9 | $ | 15.6 | $ | 843.5 | $ | 826.1 | $ | 14.8 | $ | 840.9 | |||||||||||||||||||||||||||||||||||||||||
| Plan assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair value, at the beginning of the period | $ | 634.6 | $ | — | $ | 634.6 | $ | 652.0 | $ | — | $ | 652.0 | $ | 603.1 | $ | — | $ | 603.1 | |||||||||||||||||||||||||||||||||||||||||
| Actual return | (132.2) | — | (132.2) | 31.8 | — | 31.8 | 38.5 | — | 38.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Employer contributions | 3.5 | — | 3.5 | 2.4 | — | 2.4 | 22.5 | — | 22.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Plan settlements | (1.4) | — | (1.4) | (25.9) | — | (25.9) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Benefits paid | (46.0) | — | (46.0) | (25.7) | — | (25.7) | (12.1) | — | (12.1) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair value, at the end of the period | $ | 458.5 | $ | — | $ | 458.5 | $ | 634.6 | $ | — | $ | 634.6 | $ | 652.0 | $ | — | $ | 652.0 | |||||||||||||||||||||||||||||||||||||||||
| Net benefit liabilities | $ | 153.0 | $ | 11.6 | $ | 164.6 | $ | 193.3 | $ | 15.6 | $ | 208.9 | $ | 174.1 | $ | 14.8 | $ | 188.9 | |||||||||||||||||||||||||||||||||||||||||
| Amounts recognized in Consolidated Balance Sheet: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Accrued liabilities | $ | (3.7) | $ | (1.1) | $ | (4.8) | $ | (3.8) | $ | (1.1) | $ | (4.9) | $ | (1.4) | $ | (1.4) | $ | (2.8) | |||||||||||||||||||||||||||||||||||||||||
| Other liabilities (long-term) | (149.3) | (10.5) | (159.8) | (189.5) | (14.5) | (204.0) | (172.7) | (13.4) | (186.1) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Net benefit liabilities | $ | (153.0) | $ | (11.6) | $ | (164.6) | $ | (193.3) | $ | (15.6) | $ | (208.9) | $ | (174.1) | $ | (14.8) | $ | (188.9) | |||||||||||||||||||||||||||||||||||||||||
| Accumulated contributions less than net periodic benefit cost | $ | (159.8) | $ | (19.5) | $ | (179.3) | $ | (180.0) | $ | (19.8) | $ | (199.8) | $ | (174.1) | $ | (14.8) | $ | (188.9) | |||||||||||||||||||||||||||||||||||||||||
| Amounts not yet reflected in net periodic benefit cost: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Actuarial gain (loss) | 7.0 | 7.9 | 14.9 | (13.1) | 4.2 | (8.9) | — | $ | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Prior service cost | (0.2) | — | (0.2) | (0.2) | — | (0.2) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total accumulated other comprehensive income (loss) | $ | 6.8 | $ | 7.9 | $ | 14.7 | $ | (13.3) | $ | 4.2 | $ | (9.1) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
| Net benefit liabilities | $ | (153.0) | $ | (11.6) | $ | (164.6) | $ | (193.3) | $ | (15.6) | $ | (208.9) | $ | (174.1) | $ | (14.8) | $ | (188.9) | |||||||||||||||||||||||||||||||||||||||||
| Weighted-average assumptions: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 5.21 | % | 5.30 | % | 2.73 | % | 2.72 | % | 2.84 | % | 2.73 | % | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash balance interest credit rate | 3.23 | % | N/A | 3.05 | % | N/A | 2.94 | % | N/A | ||||||||||||||||||||||||||||||||||||||||||||||||||
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The unfunded obligation decreased by $44.3 million as of December 31, 2022 (Successor) when compared to the unfunded obligation as of December 31, 2021 (Successor). The decrease was primarily attributable to $170.1 million from an increase in the discount rate and $29.3 million from change in the lump sum conversion assumptions. This decrease was partially offset by lower than expected return on plan assets of $132.2 million and $22.4 million due to increase in interest cost.
The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date assuming the actual or assumed expected date of separation for retirement.
The accumulated benefit obligation, which is presented below for all plans in the aggregate at December 31, 2022 and 2021 (Successor), is based on services rendered to date, but exclude the effect of future salary increases (in millions):
| 2022 | 2021 | |||||||||||||
| Accumulated benefit obligation | $ | 623.1 | $ | 843.5 | ||||||||||
The components of net periodic pension, retiree medical income and the weighted-average assumptions used to determine net periodic pension and retiree medical income were as follows (dollars in millions):
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | ||||||||||||||||||||||||||
Service cost (1) | $ | — | $ | — | — | 0.1 | |||||||||||||||||||||||
Interest cost (2) | 22.4 | 15.6 | 6.6 | 25.4 | |||||||||||||||||||||||||
Expected return on plan assets (2) | (38.3) | (24.7) | (12.1) | (36.5) | |||||||||||||||||||||||||
Curtailment gain recognized (2) | — | — | — | (3.3) | |||||||||||||||||||||||||
Settlement (gain) loss recognized (2) | (0.4) | 0.4 | — | (0.3) | |||||||||||||||||||||||||
Amortization of net (gain) loss (2) | (0.1) | — | 0.1 | — | |||||||||||||||||||||||||
| Net periodic pension and retiree medical income | $ | (16.4) | $ | (8.7) | $ | (5.4) | $ | (14.6) | |||||||||||||||||||||
| Discount rate | 2.73 | % | 2.84 | % | 2.30 | % | 3.16 | % | |||||||||||||||||||||
| Expected return on assets | 6.26 | % | 6.03 | % | 6.03 | % | 6.48 | % | |||||||||||||||||||||
| Cash balance interest credit rate | 3.05 | % | 2.94 | % | 2.94 | % | 3.29 | % | |||||||||||||||||||||
(1) Included in Contract drilling and General and administrative expense in our Consolidated Statements of Operations.
(2) Included in Other, net, in our Consolidated Statements of Operations.
Settlement accounting is necessary when actual lump sums paid during a fiscal year exceed the sum of the service cost and interest cost for the year. During the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor) and the year ended December 31, 2020 (Predecessor), the settlement threshold was reached for certain of our pension plans and we recognized a settlement credit of $0.4 million, a charge of $0.4 million and a credit of $0.3 million, respectively, in our Consolidated Statements of Operations.
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In March 2021, the American Rescue Plan Act of 2021 ("ARPA-21") was passed. ARPA-21 provides funding relief for U.S. qualified pension plans which has lowered pension contribution requirements and should continue to lower them over the next few years, relative to the pre-ARPA-21 contribution requirements. We currently expect to contribute approximately $7.4 million to our pension plans and to directly pay other post-retirement benefits of approximately $1.2 million in 2023. These amounts represent the minimum contributions we are required to make under relevant statutes. We do not expect to make contributions in excess of the minimum required amounts.
The pension plans' investment objectives for fund assets are to: achieve a rate of return such that contributions are minimized and future assets are available to fund liabilities, maintain liquidity sufficient to pay benefits when due, diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk and gradually de-risk the plan by increasing the allocation of investments which track the overall liabilities of the plan as the ratio of assets to liabilities improves and economic conditions warrant. The plans employ several active managers with proven long-term records in their specific investment discipline.
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Target allocations among asset categories and the fair value of each category of plan assets as of December 31, 2022 and 2021 (Successor), classified by level within the fair value hierarchy are presented below. The plans will reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in millions):
| Target range | Total | Quoted prices in active markets for identical assets (Level 1) | Significant observable inputs (Level 2) | Significant unobservable inputs (Level 3) | ||||||||||||||||||||||||||||
December 31, 2022 (1) | ||||||||||||||||||||||||||||||||
Equities: | ||||||||||||||||||||||||||||||||
| U.S. equity: | 23.9% to 33.9% | |||||||||||||||||||||||||||||||
| U.S. large cap | $ | 99.4 | $ | — | $ | 99.4 | $ | — | ||||||||||||||||||||||||
| U.S. small/mid cap | 25.4 | — | 25.4 | — | ||||||||||||||||||||||||||||
| Global Low Volatility Equity | 3.4% to 13.4% | 38.0 | — | 38.0 | — | |||||||||||||||||||||||||||
| Non-U.S. equity: | 19.7% to 29.7% | |||||||||||||||||||||||||||||||
International all cap | 50.7 | — | 50.7 | — | ||||||||||||||||||||||||||||
International small cap | 22.4 | — | 22.4 | — | ||||||||||||||||||||||||||||
| Emerging markets | 39.7 | — | 39.7 | — | ||||||||||||||||||||||||||||
Real estate equities | 3% to 13% | 49.0 | — | 49.0 | — | |||||||||||||||||||||||||||
| Fixed income: | 25% to 35% | |||||||||||||||||||||||||||||||
| Long-term corp bonds | 45.3 | — | 45.3 | — | ||||||||||||||||||||||||||||
| U.S. Treasury STRIPS | 83.7 | — | 83.7 | — | ||||||||||||||||||||||||||||
| Cash and equivalents | $0 - $5.0 | 4.9 | 4.9 | — | — | |||||||||||||||||||||||||||
| Total | $ | 458.5 | $ | 4.9 | $ | 453.6 | $ | — | ||||||||||||||||||||||||
| December 31, 2021 | ||||||||||||||||||||||||||||||||
Equities: | 53% to 69% | |||||||||||||||||||||||||||||||
| U.S. large cap | 22% to 28% | $ | 173.7 | $ | — | $ | 173.7 | $ | — | |||||||||||||||||||||||
U.S. small cap | 4% to 10% | 44.7 | — | 44.7 | — | |||||||||||||||||||||||||||
International all cap | 21% to 29% | 159.1 | — | 159.1 | — | |||||||||||||||||||||||||||
International small cap | 2% to 8% | 41.7 | — | 41.7 | — | |||||||||||||||||||||||||||
Real estate equities | 0% to 13% | 63.5 | — | 63.5 | — | |||||||||||||||||||||||||||
| Fixed income: | 25% to 35% | |||||||||||||||||||||||||||||||
| Aggregate | 9% to 19% | 73.1 | — | 73.1 | — | |||||||||||||||||||||||||||
| Core plus | 9% to 19% | 74.3 | 74.3 | — | — | |||||||||||||||||||||||||||
| Cash and equivalents | 0% to 10% | 4.5 | 4.5 | — | — | |||||||||||||||||||||||||||
| Total | $ | 634.6 | $ | 78.8 | $ | 555.8 | $ | — | ||||||||||||||||||||||||
(1)During the year ended December 31, 2022, our investment policy was updated whereby the allocation target ranges are set for general asset classes and not specific investment types.
Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the global low volatility equities include investments in a broad range of developed market global equity securities and may be held through a commingled or institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose
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objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Securities in the fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds and should be rated investment grade or above. Investments in this category should have an average investment rating of “A” or better.
The following is a description of the valuation methodologies used for the pension plan assets as of December 31, 2022 (Successor):
•Fair values of all U.S. equity securities, global low volatility equity securities, all non-U.S. equity securities and fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.
•The real estate equities categorized as Level 2 were held in three accounts (a comingled real estate investment trust ("REIT") fund, a comingled U.S. core real estate fund and a limited partnership). The assets in the REIT fund were valued daily based on a net asset value and the assets in the both the U.S. core real estate fund and the limited partnership were valued quarterly based on a net asset value.
•Cash and equivalents categorized as Level 1 were valued at cost, which approximates fair value.
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 plan's 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 increased to 7.10% at December 31, 2022 (Successor) from 6.26% at December 31, 2021 (Successor).
Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in millions):
| Pension Benefits | Other Post-Retirement Benefits | |||||||||||||
| Year ended December 31, | ||||||||||||||
| 2023 | $ | 42.4 | $ | 1.2 | ||||||||||
| 2024 | 42.4 | 1.2 | ||||||||||||
| 2025 | 41.6 | 1.1 | ||||||||||||
| 2026 | 41.0 | 1.0 | ||||||||||||
| 2027 | 40.6 | 0.9 | ||||||||||||
| 2028 through 2032 | 196.4 | 3.9 | ||||||||||||
Savings Plans
We have savings plans, (the "Savings Plan", the "Multinational Savings Plan", the "Limited Retirement Plan"), which cover eligible employees as defined within each plan. The Savings Plan includes a 401(k) savings plan feature, which allows eligible employees to make tax-deferred contributions to the plans. Contributions made to the Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements. The Limited Retirement Plan allows eligible employees in the U.K. to make tax-deferred contributions to the plan.
Historically, we made matching cash contributions to the plans. The savings plans previously matched 100% of the amount contributed by the employee generally up to a maximum of 5% of eligible salary. Matching
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contributions totaled $8.8 million for the year ended December 31, 2020 (Predecessor). Effective August 1, 2020, in light of the then current economic environment, we suspended employer matching contributions for the Savings Plan and the Multinational Savings Plan. In addition, effective December 1, 2020, the matching contributions in the Limited Retirement Plan were reduced. Employer contributions were reinstated effective January 1, 2022 whereby 100% of the amount contributed by the employee was matched up to a maximum of 4% of eligible salary. These matching contributions totaled $4.7 million for the year ended December 31, 2022 (Successor). The employer contributions increased effective January 1, 2023 whereby employee contributions are now matched up to a maximum of 5%.
13. INCOME TAXES
We generated profits of $39.7 million, $253.4 million and $373.1 million and losses of $51.0 million before income taxes in the U.S. for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively. We generated profits of $185.2 million and losses of $240.6 million, $4.8 billion and $5.1 billion before income taxes in non-U.S. jurisdictions for the year ended December 31 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively.
The components of our provision for income taxes are summarized as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Current income tax expense (benefit): | ||||||||||||||||||||||||||
| U.S. | $ | 12.4 | $ | 5.5 | $ | — | $ | (135.3) | ||||||||||||||||||
| Non-U.S. | 22.8 | 52.2 | 34.4 | (18.4) | ||||||||||||||||||||||
| 35.2 | 57.7 | 34.4 | (153.7) | |||||||||||||||||||||||
| Deferred income tax expense (benefit): | ||||||||||||||||||||||||||
| U.S. | 8.5 | (6.6) | — | (92.9) | ||||||||||||||||||||||
| Non-U.S. | (0.6) | (14.7) | (18.2) | (12.8) | ||||||||||||||||||||||
| 7.9 | (21.3) | (18.2) | (105.7) | |||||||||||||||||||||||
| Total income tax expense (benefit) | $ | 43.1 | $ | 36.4 | $ | 16.2 | $ | (259.4) | ||||||||||||||||||
CARES Act
The U.S. Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") was enacted on March 27, 2020 and introduced various corporate tax relief measures into law. Among other things, the CARES Act allows net operating losses ("NOLs") generated in 2019 and 2020 to be carried back to each of the five preceding years. During 2020, we recognized a tax benefit of $122.1 million associated with the carryback of NOLs to recover taxes paid in prior years.
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Deferred Taxes
The components of deferred income tax assets and liabilities are summarized as follows (in millions):
| December 31, 2022 | December 31, 2021 | |||||||||||||
Deferred tax assets: | ||||||||||||||
| Net operating loss carryforwards | $ | 3,028.7 | $ | 2,297.5 | ||||||||||
| Property and equipment | 1,454.8 | 1,361.6 | ||||||||||||
| Interest limitation carryforwards | 193.4 | 74.8 | ||||||||||||
| Foreign tax credits | 60.7 | 105.7 | ||||||||||||
| Employee benefits, including share-based compensation | 43.1 | 51.2 | ||||||||||||
| Premiums on long-term debt | 8.1 | 9.7 | ||||||||||||
| Other | 20.1 | 15.4 | ||||||||||||
| Total deferred tax assets | 4,808.9 | 3,915.9 | ||||||||||||
| Valuation allowance | (4,720.3) | (3,829.0) | ||||||||||||
| Net deferred tax assets | 88.6 | 86.9 | ||||||||||||
Deferred tax liabilities: | ||||||||||||||
| Property and equipment | — | — | ||||||||||||
| Other | (19.4) | (14.5) | ||||||||||||
| Total deferred tax liabilities | (19.4) | (14.5) | ||||||||||||
| Net deferred tax asset | $ | 69.2 | $ | 72.4 | ||||||||||
The realization of substantially all of our deferred tax assets is dependent upon generating sufficient taxable income during future periods in various jurisdictions in which we operate. Realization of certain of our deferred tax assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change.
As of December 31, 2022 (Successor), we had gross deferred tax assets of $3.0 billion relating to $12.9 billion of NOL carryforwards, $60.7 million of U.S. foreign tax credits (“FTCs”), and $193.4 million of U.S. and Luxembourg interest limitation carryforwards, which can be used to reduce our income taxes payable in future years. NOL carryforwards, which were generated in various jurisdictions worldwide, include $11.8 billion that do not expire and $1.1 billion that will expire, if not utilized, between 2023 and 2040. Deferred tax assets for NOL carryforwards as of December 31, 2022 (Successor) include $2.1 billion, $605.7 million, $79.2 million, and $56.1 million pertaining to NOL carryforwards in Luxembourg, the United States, Switzerland, and the U.K., respectively. The U.S. FTCs expire between 2023 and 2026. Interest limitation carryforwards generally do not expire. Additionally, as a result of our emergence from bankruptcy, the utilization of certain U.S. deferred tax assets including, but not limited to, NOL carryforwards, FTCs, and interest limitation carryforwards is limited to $0.5 million annually. We have recognized a $4.7 billion valuation allowance as of December 31, 2022 (Successor) on deferred tax assets relating to those assets for which we are not more likely than not to realize due to the inability to generate sufficient taxable income in the period and/or of the character necessary to use the benefit of the deferred tax assets.
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During the year ended December 31, 2022 (Successor) and the eight months ended December 31, 2021 (Successor), we recognized $1.5 million deferred tax expense and $9.8 million deferred tax benefit associated with changes in deferred tax asset valuation allowances. Given current industry conditions and recent historical losses, we do not project reliable future income other than from existing drilling contracts and other known sources of future income. If industry conditions continue to improve, which is generally evidenced by increased contract backlog and increased contract day rates, we may rely on projected taxable income from future drilling contracts for the recognition of deferred tax assets.
Effective Tax Rate
Valaris Limited is domiciled and resident 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 as there is not an income tax regime in Bermuda. Legacy Valaris was domiciled and resident in the U.K. The income of our non-U.K. subsidiaries was generally not subject to U.K. 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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Our consolidated effective income tax rate for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively, differs from the Bermuda and U.K. statutory income tax rates as follows:
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
Bermuda (Successor)/ U.K. (Predecessor) statutory income tax rate | — | % | — | % | 19.0 | % | 19.0 | % | ||||||||||||||||||
| Asset impairments | — | — | (3.2) | (12.5) | ||||||||||||||||||||||
Non-Bermuda (Successor) taxes | 22.8 | 376.0 | — | — | ||||||||||||||||||||||
Non-U.K. (Predecessor) taxes | — | — | 1.0 | (2.8) | ||||||||||||||||||||||
Resolution of prior year items | (7.0) | 216.2 | (0.4) | 1.8 | ||||||||||||||||||||||
| Switzerland Tax Reform | — | (188.3) | — | — | ||||||||||||||||||||||
| Valuation allowance | 0.6 | (119.5) | (1.8) | (1.5) | ||||||||||||||||||||||
| U.S. tax reform and U.S. CARES Act | — | — | — | 2.4 | ||||||||||||||||||||||
| Contract termination | 2.8 | — | — | — | ||||||||||||||||||||||
| Other | — | — | (15.0) | (1.3) | ||||||||||||||||||||||
| Effective income tax rate | 19.2 | % | 284.4 | % | (0.4) | % | 5.1 | % | ||||||||||||||||||
Our 2022 consolidated effective income tax rate includes $10.3 million associated with the impact of various discrete items, including $17.2 million income tax benefit associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset primarily by tax expense attributable to income associated with a contract termination.
Our eight months ended December 31, 2021 (Successor) consolidated effective income tax rate includes $14.3 million associated with the impact of various discrete items, including $29.7 million income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $15.4 million of tax benefit related to deferred taxes associated with Switzerland tax reform.
Our four months ended April 30, 2021 (Predecessor) consolidated effective income tax rate included $2.2 million associated with the impact of various discrete items, including $21.5 million of income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $19.3 million of tax benefit related to fresh start accounting adjustments.
Our 2020 consolidated effective income tax rate includes a $322.4 million tax benefit associated with the impact of various discrete tax items, including restructuring transactions, impairments of rigs and other assets, implementation of the U.S. CARES Act, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years, rig sales, reorganization items and the resolution of other prior period tax matters.
Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor) were 73.6%, 213.9%, (12.9)% and (7.6)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-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.
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On February 3, 2020, as a result of a 2019 acquisition, the Predecessor became the obligor on 4.875% Senior notes due 2022, 5.40% Senior notes due 2042, 7.375% Senior notes due 2025, 4.75% Senior notes due 2024 and 5.85% Senior notes due 2044. We recognized a tax benefit of $66.0 million during the year ended December 31, 2020 in connection with this transaction.
Unrecognized Tax Benefits
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.
As of December 31, 2022 (Successor), we had $217.6 million of unrecognized tax benefits, of which $187.2 million was included in Other liabilities on our Consolidated Balance Sheet, $30.2 million, which is associated with tax positions taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets and $0.2 million was presented as a reduction of long-term income tax receivable.
As of December 31, 2021 (Successor), we had $235.1 million of unrecognized tax benefits, of which $202.9 million was included in Other liabilities on our Consolidated Balance Sheet, $31.2 million, which is associated with tax positions taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets and $1.0 million was presented as a reduction of long-term income tax receivable.
If recognized, $183.9 million of the $217.6 million unrecognized tax benefits as of December 31, 2022 (Successor) would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), respectively (in millions) follows:
| Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | |||||||||||||||||||||
| Balance, beginning of period | $ | 235.1 | $ | 235.4 | $ | 237.7 | |||||||||||||||||
| Settlements with taxing authorities | (16.5) | (6.6) | — | ||||||||||||||||||||
| Increases in unrecognized tax benefits as a result of tax positions taken during the current year | 11.2 | 6.9 | 12.6 | ||||||||||||||||||||
| Impact of foreign currency exchange rates | (9.7) | (10.5) | (17.6) | ||||||||||||||||||||
| Lapse of applicable statutes of limitations | (4.5) | (20.2) | (0.2) | ||||||||||||||||||||
| Increase in unrecognized tax benefits as a result of tax positions taken during prior years | 3.0 | 34.6 | 2.9 | ||||||||||||||||||||
| Decreases in unrecognized tax benefits as a result of tax positions taken during prior years | (1.0) | (4.5) | — | ||||||||||||||||||||
| Balance, end of period | $ | 217.6 | $ | 235.1 | $ | 235.4 | |||||||||||||||||
Accrued interest and penalties totaled $87.8 million and $100.5 million as of December 31, 2022 (Successor) and 2021 (Successor), respectively, and were included in Other liabilities on our Consolidated Balance Sheets. We recognized a net benefit of $12.5 million, and net expense of $20.3 million, $13.5 million and $13.8 million associated with interest and penalties during the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively. Interest and penalties are included in Current income tax expense in our Consolidated Statements of Operations.
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Three of our subsidiaries file or previously filed U.S. tax returns and the tax returns of one or more of these subsidiaries is under exam for years 2009 to 2012, and for 2014 and subsequent years. None of these examinations are expected to have a significant impact on the Company's consolidated results of operations and cash flows. Tax years as early as 2005 remain subject to examination in the other major tax jurisdictions in which we operated.
Statutes of limitations applicable to certain of our tax positions lapsed during the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), resulting in net income tax benefits, inclusive of interest and penalties, of $4.5 million, $17.9 million, $0.2 million and $4.3 million, respectively.
Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2023. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $50.0 million, inclusive of $11.4 million of accrued interest and penalties, all of which would impact our consolidated effective income tax rate if recognized.
Tax Assessments
During 2019, the Luxembourg tax authorities issued aggregate tax assessments totaling approximately €142.0 million (approximately $161.5 million converted at then-current exchange rates) related to tax years 2014, 2015 and 2016 for several of Rowan's Luxembourg subsidiaries. We recorded a liability for uncertain tax positions of €93.0 million (approximately $105.7 million converted at then-current exchange rates) in purchase accounting related to these assessments. During the first quarter of 2020, in connection with the administrative appeals process, the tax authority withdrew assessments of €142.0 million (approximately $161.5 million converted at then-current exchange rates), accepting the associated tax returns as previously filed. Accordingly, we de-recognized previously accrued liabilities for uncertain tax positions and net wealth taxes of €79.0 million (approximately $89.8 million converted at then-current exchange rates) and €2.0 million (approximately $2.3 million converted at then-current exchange rates), respectively. The de-recognition of amounts related to these assessments was recognized as a tax benefit during the three-month period ended March 31, 2020 and is included in Changes in operating assets and liabilities on the Consolidated Statements of Cash Flows for the year ended December 31, 2020 (Predecessor). On December 31, 2021 (Successor), we de-recognized the remaining liability for uncertain tax position balance of €14.0 million (approximately $15.9 million converted at then-current exchange rates) upon the lapse of the applicable statute of limitations.
During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $68.8 million converted at the current period-end exchange rate) 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 million payment (approximately $29.0 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have a $17.8 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2022 (Successor). We believe our tax returns are materially correct as filed, and we are vigorously contesting these assessments. Although the outcome of such assessments and related administrative proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.
Undistributed Earnings
Dividend income received by Valaris Limited from its subsidiaries is exempt from Bermuda taxation. We do not provide deferred taxes on undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. As of December 31, 2022 (Successor), the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $289.5 million. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we would be subject to additional income taxes. The unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate as of December 31, 2022 (Successor).
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14. COMMITMENTS AND CONTINGENCIES
Newbuild Options
We have construction agreements, as amended, with a shipyard that provide for, among other things, an option construct whereby the Company has the right, but not the obligation, to take delivery of either or both Newbuild Drillships, on or before December 31, 2023. Under the amended agreements, the purchase prices for the rigs are estimated to be $119.1 million for VALARIS DS-13 and $218.3 million for VALARIS DS-14, assuming a December 31, 2023 delivery date. Delivery can be requested any time prior to December 31, 2023 with a downward purchase price adjustment based on predetermined terms. If the Company elects not to purchase the rigs, the Company has no further obligations to the shipyard.
ARO Newbuild Funding Obligations
In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. ARO has plans to 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 from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the two newbuilds ordered in January 2020 and is actively exploring financing options for remaining payments due upon delivery. In the event ARO has insufficient cash from operations 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. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered, on a proportionate basis.
Letters of Credit
In the ordinary course of business with customers and others, we have entered into letters of credit to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Letters of credit outstanding as of December 31, 2022 (Successor) totaled $141.4 million and are issued under facilities provided by various banks and other financial institutions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2022 (Successor), we had collateral deposits in the amount of $20.7 million with respect to these agreements.
Patent Litigation
In December 2022, a subsidiary of Transocean Ltd. commenced an arbitration proceeding against us alleging breach of a license agreement related to certain dual-activity drilling patents. We are unable to estimate our potential exposure, if any, to the proceeding at this time but do not believe that our ultimate liability, if any, resulting from this proceeding will have a material effect on our consolidated financial condition, results of operations or cash flows. We do not believe that we have breached the license agreement and intend to defend ourselves vigorously against this claim.
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.
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15. LEASES
We have operating leases for office space, facilities, equipment, employee housing and certain rig berthing facilities. For all asset classes, except office space, we account for the lease component and the non-lease component as a single lease component. Our leases have remaining lease terms of less than one year to nine years, some of which include options to extend.
We evaluate the carrying value of our right-of-use assets on a periodic basis to identify events or changes in circumstances, such as lease abandonment, that indicate that the carrying value of such right-of-use assets may be impaired.
The components of lease expense are as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Long-term operating lease cost | $ | 13.4 | $ | 12.9 | $ | 9.1 | $ | 23.3 | ||||||||||||||||||
| Short-term operating lease cost | 16.2 | 15.3 | 7.0 | 19.2 | ||||||||||||||||||||||
| Sublease income | (0.4) | (0.3) | (0.1) | (2.3) | ||||||||||||||||||||||
| Total operating lease cost | $ | 29.2 | $ | 27.9 | $ | 16.0 | $ | 40.2 | ||||||||||||||||||
Supplemental balance sheet information related to our operating leases is as follows (in millions, except lease term and discount rate):
| December 31, 2022 | December 31, 2021 | ||||||||||
| $ | 21.0 | $ | 20.5 | ||||||||
| $ | 9.4 | $ | 10.0 | ||||||||
| 13.8 | 12.5 | ||||||||||
| Total operating lease liabilities | $ | 23.2 | $ | 22.5 | |||||||
| Weighted-average remaining lease term (in years) | 5.0 | 4.8 | |||||||||
Weighted-average discount rate (1) | 7.48 | % | 7.27 | % | |||||||
(1)Represents our estimated incremental borrowing cost on a secured basis for similar terms as the underlying leases.
For the year ended December 31, 2022 (Successor), cash paid for amounts included in the measurement of our operating lease liabilities was $14.0 million. During the eight months ended December 31, 2021 (Successor) and during the four months ended April 30, 2021 (Predecessor), cash paid for amounts included in the measurement of our operating lease liabilities were $11.7 million and $7.1 million, respectively. For the years ended December 31, 2020 (Predecessor), cash paid for amounts included in the measurement of our operating lease liabilities was $23.5 million.
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Maturities of lease liabilities as of December 31, 2022 (Successor) were as follows (in millions):
| 2023 | $ | 10.7 | |||
| 2024 | 3.5 | ||||
| 2025 | 2.7 | ||||
| 2026 | 2.4 | ||||
| 2027 | 2.4 | ||||
| Thereafter | 6.1 | ||||
| Total lease payments | $ | 27.8 | |||
| Less imputed interest | (4.6) | ||||
| Total | $ | 23.2 | |||
Predecessor
On October 28, 2020, the Bankruptcy Court approved the rejection of certain unexpired office leases and related subleases. The various lease rejections were effective as of September 30, 2020 and October 31, 2020. We recorded an estimated allowed claim of $4.4 million and recognized an expense in Reorganization items, net in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor). Also, during the year ended December 31, 2020 (Predecessor), in connection with office lease rejections and a related amendment to the terms of the lease for our corporate headquarters in Houston, Texas, we recognized net gains in Reorganization items of $9.8 million and $1.7 million, respectively, which included the write-offs of associated leasehold improvements.
16. SEGMENT INFORMATION
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 Lease Agreements. Floaters, Jackups and ARO are also reportable segments.
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". We measure segment assets as Property and equipment, net.
The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 5 - Equity Method Investment in ARO" for additional information on ARO and related arrangements.
Segment information for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), respectively are presented below (in millions).
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Year Ended December 31, 2022 (Successor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 700.5 | $ | 744.2 | $ | 459.5 | $ | 157.8 | $ | (459.5) | $ | 1,602.5 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 646.0 | 538.9 | 341.8 | 76.4 | (219.9) | 1,383.2 | |||||||||||||||||||||||||||||
| Loss on impairment | 34.5 | — | — | — | — | 34.5 | |||||||||||||||||||||||||||||
| Depreciation | 50.0 | 36.1 | 63.4 | 4.6 | (62.9) | 91.2 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 18.7 | — | 62.2 | 80.9 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 24.5 | 24.5 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (30.0) | $ | 169.2 | $ | 35.6 | $ | 76.8 | $ | (214.4) | $ | 37.2 | |||||||||||||||||||||||
| Property and equipment, net | $ | 487.5 | $ | 391.7 | $ | 775.6 | $ | 56.8 | $ | (734.4) | $ | 977.2 | |||||||||||||||||||||||
| Capital expenditures | $ | 152.9 | $ | 53.5 | $ | 24.6 | $ | — | $ | (24.0) | $ | 207.0 | |||||||||||||||||||||||
Eight Months Ended December 31, 2021 (Successor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 254.5 | $ | 487.1 | $ | 307.1 | $ | 93.4 | $ | (307.1) | $ | 835.0 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 250.7 | 365.2 | 246.2 | 38.9 | (176.9) | 724.1 | |||||||||||||||||||||||||||||
| Depreciation | 31.0 | 32.0 | 44.2 | 2.8 | (43.9) | 66.1 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 13.6 | — | 44.6 | 58.2 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 6.1 | 6.1 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (27.2) | $ | 89.9 | $ | 3.1 | $ | 51.7 | $ | (124.8) | $ | (7.3) | |||||||||||||||||||||||
| Property and equipment, net | $ | 408.2 | $ | 401.9 | $ | 730.6 | $ | 46.0 | $ | (695.8) | $ | 890.9 | |||||||||||||||||||||||
| Capital expenditures | $ | 26.0 | $ | 23.7 | $ | 41.8 | $ | — | $ | (41.3) | $ | 50.2 | |||||||||||||||||||||||
Four Months Ended April 30, 2021 (Predecessor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 115.7 | $ | 232.4 | $ | 163.5 | $ | 49.3 | $ | (163.5) | $ | 397.4 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 106.5 | 175.0 | 116.1 | 19.9 | (73.7) | 343.8 | |||||||||||||||||||||||||||||
| Loss on impairment | 756.5 | — | — | — | — | 756.5 | |||||||||||||||||||||||||||||
| Depreciation | 72.1 | 69.7 | 21.0 | 14.8 | (18.0) | 159.6 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 4.2 | — | 26.5 | 30.7 | |||||||||||||||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 3.1 | 3.1 | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (819.4) | $ | (12.3) | $ | 22.2 | $ | 14.6 | $ | (95.2) | $ | (890.1) | |||||||||||||||||||||||
| Property and equipment, net | $ | 419.3 | $ | 401.4 | $ | 730.7 | $ | 50.5 | $ | (692.8) | $ | 909.1 | |||||||||||||||||||||||
| Capital expenditures | $ | 3.3 | $ | 5.4 | $ | 14.9 | $ | — | $ | (14.9) | $ | 8.7 | |||||||||||||||||||||||
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Year Ended December 31, 2020 (Predecessor)
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | ||||||||||||||||||||||||||||||
| Revenues | $ | 505.8 | $ | 765.3 | $ | 549.4 | $ | 156.1 | $ | (549.4) | $ | 1,427.2 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Contract drilling (exclusive of depreciation) | 566.1 | 659.5 | 388.2 | 82.8 | (226.2) | 1,470.4 | |||||||||||||||||||||||||||||
| Loss on impairment | 3,386.2 | 254.3 | — | 5.7 | — | 3,646.2 | |||||||||||||||||||||||||||||
| Depreciation | 262.8 | 217.2 | 54.8 | 44.8 | (38.8) | 540.8 | |||||||||||||||||||||||||||||
| General and administrative | — | — | 24.2 | — | 190.4 | 214.6 | |||||||||||||||||||||||||||||
| Other operating income | 118.1 | — | — | — | — | 118.1 | |||||||||||||||||||||||||||||
| Equity in losses of ARO | — | — | — | — | (7.8) | (7.8) | |||||||||||||||||||||||||||||
| Operating income (loss) | $ | (3,591.2) | $ | (365.7) | $ | 82.2 | $ | 22.8 | $ | (482.6) | $ | (4,334.5) | |||||||||||||||||||||||
| Property and equipment, net | $ | 6,413.4 | $ | 3,912.6 | $ | 736.2 | $ | 577.9 | $ | (679.6) | $ | 10,960.5 | |||||||||||||||||||||||
| Capital expenditures | $ | 25.1 | $ | 58.9 | $ | 136.1 | $ | — | $ | (126.3) | $ | 93.8 | |||||||||||||||||||||||
Information about Geographic Areas
As of December 31, 2022 (Successor), our Floaters segment consisted of 11 drillships, four dynamically positioned semisubmersible rigs and one moored semisubmersible rig deployed in various locations. Our Jackups segment consisted of 28 jackup rigs which were deployed in various locations and our Other segment consisted of eight jackup rigs which are leased to our 50/50 unconsolidated joint venture with Saudi Aramco.
As of December 31, 2022 (Successor), the geographic distribution of our and ARO's drilling rigs was as follows:
| Floaters | Jackups | Other | Total Valaris | ARO | |||||||||||||||||||||||||
| North & South America | 7 | 6 | — | 13 | — | ||||||||||||||||||||||||
| Europe & the Mediterranean | 4 | 12 | — | 16 | — | ||||||||||||||||||||||||
| Middle East & Africa | 3 | 6 | 8 | 17 | 7 | ||||||||||||||||||||||||
| Asia & Pacific Rim | 2 | 4 | — | 6 | — | ||||||||||||||||||||||||
| Total | 16 | 28 | 8 | 52 | 7 | ||||||||||||||||||||||||
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.
We are a party to contracts whereby we have the option to take delivery of two recently constructed drillships that are not included in the table above.
ARO has ordered two newbuild jackups which are under construction in the Middle East that are not included in the table above.
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Information by country for those countries that account for more than 10% of our long-lived assets, was as follows (in millions):
| Long-lived Assets | |||||||||||
| December 31, 2022 | December 31, 2021 | ||||||||||
| United Kingdom | $ | 185.2 | $ | 142.4 | |||||||
| United States | 166.3 | 152.1 | |||||||||
| Spain | 117.7 | 145.8 | |||||||||
| Brazil | 102.0 | 57.6 | |||||||||
Other countries(1) | 427.0 | 413.5 | |||||||||
| Total | $ | 998.2 | $ | 911.4 | |||||||
(1)Other countries includes countries where individually we had long-lived assets representing less than 10% of total long-lived assets
For purposes of our long-lived asset geographic disclosure, we attribute assets to the geographic location of the drilling rig or operating lease, in the case of our right-of-use assets, as of the end of the applicable year.
17. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net, consisted of the following (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Trade | $ | 345.7 | $ | 296.8 | |||||||
| Income tax receivables | 93.6 | 151.1 | |||||||||
| Other | 24.6 | 12.7 | |||||||||
| 463.9 | 460.6 | ||||||||||
| Allowance for doubtful accounts | (14.8) | (16.4) | |||||||||
| $ | 449.1 | $ | 444.2 | ||||||||
Other current assets consisted of the following (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Deferred costs | $ | 59.1 | $ | 26.9 | |||||||
| Prepaid taxes | 44.6 | 44.4 | |||||||||
| Prepaid expenses | 17.5 | 23.1 | |||||||||
| Other | 27.4 | 23.4 | |||||||||
| $ | 148.6 | $ | 117.8 | ||||||||
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Accrued liabilities and other consisted of the following (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Deferred revenue | $ | 78.0 | $ | 45.8 | |||||||
| Personnel costs | 55.8 | 47.3 | |||||||||
| Income and other taxes payable | 41.4 | 45.7 | |||||||||
| Accrued claims | 27.2 | 17.3 | |||||||||
| Lease liabilities | 9.4 | 10.0 | |||||||||
| Accrued interest | 7.6 | 7.6 | |||||||||
| Other | 28.5 | 22.5 | |||||||||
| $ | 247.9 | $ | 196.2 | ||||||||
Other liabilities consisted of the following (in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Unrecognized tax benefits (inclusive of interest and penalties) | $ | 275.0 | $ | 303.4 | |||||||
| Pension and other post-retirement benefits | 159.8 | 204.0 | |||||||||
| Other | 80.8 | 51.0 | |||||||||
| $ | 515.6 | $ | 558.4 | ||||||||
Consolidated Statements of Operations Information
Repair and maintenance expense related to continuing operations was as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Repair and maintenance expense | $ | 175.2 | $ | 76.3 | $ | 48.4 | $ | 200.4 | ||||||||||||||||||
Other, net, consisted of the following (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Net gain on sale of property | $ | 141.2 | $ | 21.2 | $ | 6.0 | $ | 11.8 | ||||||||||||||||||
| Net periodic pension income, excluding service cost | 16.4 | 8.7 | 5.4 | 14.6 | ||||||||||||||||||||||
| Net foreign currency exchange gains (losses) | 12.2 | 8.1 | 13.4 | (11.0) | ||||||||||||||||||||||
| Gain on bargain purchase and measurement period adjustments | — | — | — | (6.3) | ||||||||||||||||||||||
| Gain on extinguishment of debt | — | — | — | 3.1 | ||||||||||||||||||||||
| Other income | 0.1 | 0.1 | 1.1 | 3.8 | ||||||||||||||||||||||
| $ | 169.9 | $ | 38.1 | $ | 25.9 | $ | 16.0 | |||||||||||||||||||
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Consolidated Statements of Cash Flows Information
Our restricted cash of $24.4 million, $35.9 million and $11.4 million at December 31, 2022 (Successor), December 31, 2021 (Successor) and December 31, 2020 (Predecessor), respectively, consists primarily of $20.7 million, $31.1 million and $5.8 million of collateral on letters of credit for each respective period. See "Note 14 - Commitments and Contingencies" for more information regarding our letters of credit.
Net cash used in operating activities attributable to the net change in operating assets and liabilities was as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| (Increase) decrease in accounts receivable | $ | (6.9) | $ | (18.3) | $ | 23.2 | $ | 53.3 | ||||||||||||||||||
| (Increase) decrease in other assets | (104.6) | (48.4) | 27.3 | (63.8) | ||||||||||||||||||||||
| Increase (decrease) in liabilities | 146.9 | 71.4 | 18.0 | (11.5) | ||||||||||||||||||||||
| $ | 35.4 | $ | 4.7 | $ | 68.5 | $ | (22.0) | |||||||||||||||||||
Additional cash flow information was as follows (in millions):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Cash paid for interest and taxes | ||||||||||||||||||||||||||
| Interest paid, net of amounts capitalized | $ | 44.2 | $ | 22.8 | $ | — | $ | 190.0 | ||||||||||||||||||
| Income taxes paid (refunded), net | $ | 5.6 | $ | 23.5 | $ | (16.9) | $ | 48.5 | ||||||||||||||||||
| Non-cash investing activities | ||||||||||||||||||||||||||
Accruals for capital expenditures as of period end (1) | $ | 22.1 | $ | 9.3 | $ | 6.5 | $ | 5.4 | ||||||||||||||||||
(1) Accruals for capital expenditures were excluded from investing activities in our Consolidated Statements of Cash Flows.
Capitalized interest totaled $1.2 million during the year ended December 31, 2022 (Successor). During the eight months ended December 31, 2021 (Successor) and during the four months ended April 30, 2021 (Predecessor), there was no capitalized interest. Capitalized interest totaled $1.3 million during the year ended December 31, 2020 (Predecessor).
Amortization, net, includes amortization of deferred mobilization revenues and costs, deferred capital upgrade revenues, intangible amortization and other amortization.
Other adjustments to reconcile net loss to net cash used in operating activities includes provisions for inventory reserves, bad debt expense, and other items.
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Concentration of Risk
Credit Risk - We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and short-term investments. We mitigate our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which generally have been within our expectations.
Customer Concentration - Consolidated revenues with customers that individually contributed 10% or more of revenue were as follows:
| Successor | |||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||
| Floaters | Jackups | Other | Total | Floaters | Jackups | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| BP plc ("BP") | 6 | % | 3 | % | 6 | % | 15 | % | 2 | % | 2 | % | 7 | % | 11 | % | |||||||||||||||||||||||||||||||
Other customers(1) | 38 | % | 43 | % | 4 | % | 85 | % | 29 | % | 56 | % | 4 | % | 89 | % | |||||||||||||||||||||||||||||||
| 44 | % | 46 | % | 10 | % | 100 | % | 31 | % | 58 | % | 11 | % | 100 | % | ||||||||||||||||||||||||||||||||
| Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||
| Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||
| Floaters | Jackups | Other | Total | Floaters | Jackups | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| BP | 5 | % | 2 | % | 7 | % | 14 | % | 3 | % | 2 | % | 6 | % | 11 | % | |||||||||||||||||||||||||||||||
Other customers(1) | 24 | % | 57 | % | 5 | % | 86 | % | 32 | % | 52 | % | 5 | % | 89 | % | |||||||||||||||||||||||||||||||
| 29 | % | 59 | % | 12 | % | 100 | % | 35 | % | 54 | % | 11 | % | 100 | % | ||||||||||||||||||||||||||||||||
(1) Other customers includes customers that individually contributed to less than 10% of our total revenues.
149
Geographic Concentration - For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues for locations that individually had 10% or more of revenue were as follows (in millions):
| Successor | |||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2022 | Eight Months Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||
| Floaters | Jackups | Other | Total | Floaters | Jackups | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| U.S. Gulf of Mexico | $ | 230.9 | $ | 21.3 | $ | 99.0 | $ | 351.2 | $ | 52.8 | $ | 0.7 | $ | 56.4 | $ | 109.9 | |||||||||||||||||||||||||||||||
| United Kingdom | — | 264.5 | — | 264.5 | — | 185.2 | — | 185.2 | |||||||||||||||||||||||||||||||||||||||
| Saudi Arabia | — | 78.3 | 58.7 | 137.0 | — | 55.3 | 37.0 | 92.3 | |||||||||||||||||||||||||||||||||||||||
| Norway | — | 114.6 | — | 114.6 | — | 123.9 | — | 123.9 | |||||||||||||||||||||||||||||||||||||||
| Mexico | 13.9 | 58.1 | — | 72.0 | 37.0 | 40.8 | — | 77.8 | |||||||||||||||||||||||||||||||||||||||
Other countries(1) | 455.7 | 207.5 | — | 663.2 | 164.8 | 81.1 | — | 245.9 | |||||||||||||||||||||||||||||||||||||||
| $ | 700.5 | $ | 744.3 | $ | 157.7 | $ | 1,602.5 | $ | 254.6 | $ | 487.0 | $ | 93.4 | $ | 835.0 | ||||||||||||||||||||||||||||||||
| Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||
| Four Months Ended April 30, 2021 | Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||
| Floaters | Jackups | Other | Total | Floaters | Jackups | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| U.S. Gulf of Mexico | $ | 47.9 | $ | 0.2 | $ | 26.3 | $ | 74.4 | $ | 133.4 | $ | 27.0 | $ | 81.0 | $ | 241.4 | |||||||||||||||||||||||||||||||
| United Kingdom | — | 75.7 | — | 75.7 | — | 211.3 | — | 211.3 | |||||||||||||||||||||||||||||||||||||||
| Saudi Arabia | — | 30.5 | 23.1 | 53.6 | — | 126.9 | 73.9 | 200.8 | |||||||||||||||||||||||||||||||||||||||
| Norway | — | 73.3 | — | 73.3 | — | 188.5 | — | 188.5 | |||||||||||||||||||||||||||||||||||||||
| Mexico | 21.6 | 22.7 | — | 44.3 | 60.9 | 51.2 | — | 112.1 | |||||||||||||||||||||||||||||||||||||||
Other countries(1) | 46.1 | 30.0 | — | 76.1 | 311.5 | 160.4 | 1.2 | 473.1 | |||||||||||||||||||||||||||||||||||||||
| $ | 115.6 | $ | 232.4 | $ | 49.4 | $ | 397.4 | $ | 505.8 | $ | 765.3 | $ | 156.1 | $ | 1,427.2 | ||||||||||||||||||||||||||||||||
(1)Other countries includes locations that individually contributed to less than 10% of total revenues.
18. RELATED PARTIES
See "Note 5 - Equity Method Investment in ARO" for information in our equity method investment in ARO and associated related party transactions.
Mr. Joseph Goldschmid is a director of the Company and an employee of T. Rowe Price effective December 29, 2021 when his employer, Oak Hill Advisors, was acquired by T. Rowe Price. T. Rowe Price provides administrative services for the Company's 401(k) Plan. During the year ended December 31, 2022 (Successor) we incurred expense of $4.7 million and had no payable as of December 31, 2022 (Successor) related to the employer matching contributions to the Company's 401(k) Plan made in 2022. As the employer matching contributions to the Company's 401(k) Plan were suspended during the eight months ended December 31, 2021 (Successor) and the administrative fees are borne by the participants of the plan, no amounts were included in the Company's expenses during the eight months ended December 31, 2021 (Successor) or payables as of December 31, 2021 (Successor).
150
Mr. Deepak Munganahalli is a director of the Successor Company and was an employee of Joulon until September 2022. The Company regularly does business with several subsidiaries and affiliates of Joulon, which provide goods and services to the Company, including asset management services, structural engineering services, rig repair services, high pressure equipment, inspection services, riser related services (including storage, inspection, preservation and repair), and rig stacking and maintenance arrangements. We incurred expense of $15.4 million and $8.8 million during the year ended December 31, 2022 (Successor) and the eight months ended December 31, 2021 (Successor), respectively, related to these goods and services and had $0.5 million and $2.5 million of payables to them as of December 31, 2022 and 2021 (Successor), respectively.
151
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures – We have established disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and made known to the officers who certify the Company’s financial reports and to other members of senior management and the board of directors as appropriate to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, are effective.
Changes in Internal Controls – There were no material changes in our internal control over financial reporting during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.
Item 9B. Other Information
Not applicable.
152
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item with respect to our directors, corporate governance matters, committees of the board of directors and Section 16(a) of the Exchange Act is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("Proxy Statement") to be filed with the SEC not later than 120 days after the end of our fiscal year ended December 31, 2022 and incorporated herein by reference.
The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.
The guidelines and procedures of the board of directors are outlined in our Corporate Governance Policy. The committees of the board of directors operate under written charters adopted by the board of directors. The Corporate Governance Policy and committee charters are available on our website at www.valaris.com in the Governance Documents section and are available in print without charge by contacting our Investor Relations Department.
We have a Code of Conduct that applies to all directors and employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Conduct is available on our website at www.valaris.com in the Governance Documents section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Conduct by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Conduct, our Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the board of directors and director attendance at the Annual General Meeting of Shareholders.
Item 11. Executive Compensation
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
153
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Equity Compensation Plan Information
The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2022:
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1) | |||||||||||||||||
| (a) | (b)(1) | (c) | ||||||||||||||||||
| Equity compensation plans approved by security holders | — | $ | — | — | ||||||||||||||||
Equity compensation plans not approved by security holders (2) | 1,674,952 | — | 7,106,439 | |||||||||||||||||
| Total | 1,674,952 | $ | — | 7,106,439 | ||||||||||||||||
(1)Restricted share units do not have an exercise price and, thus, are not reflected in this column.
(2)The number of awards granted for performance awards reflect the shares that would be granted if the target level of performance were to be achieved.
Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
PART IV
154
Item 15. Exhibits, Financial Statement Schedules
| (a) | The following documents are filed as part of this report: | |||||||
| 1. Financial Statements | ||||||||
Reports of Independent Registered Public Accounting Firm (KPMG LLP, Houston, Texas, Auditor Firm ID: 185) | ||||||||
| Consolidated Statements of Operations | ||||||||
| Consolidated Statements of Comprehensive Income | ||||||||
| Consolidated Balance Sheets | ||||||||
| Consolidated Statements of Cash Flows | ||||||||
| Notes to Consolidated Financial Statements | ||||||||
| 2. Exhibits | |||||
155
| 4.7 | ||||||||
| 4.8 | ||||||||
| 10.1 | ||||||||
| 10.2 | ||||||||
| 10.3 | ||||||||
| 10.4 | ||||||||
| 10.5 | ||||||||
| 10.6 | ||||||||
| 10.7 | ||||||||
| +10.8 | ||||||||
| +10.9 | ||||||||
| +10.10 | ||||||||
| +10.11 | ||||||||
| +10.12 | ||||||||
| +10.13 | ||||||||
| +10.14 | ||||||||
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| +10.15 | ||||||||
| +10.16 | ||||||||
| +10.17 | ||||||||
| +10.18 | ||||||||
| +10.19 | ||||||||
| +10.20 | ||||||||
| +10.21 | ||||||||
| +10.22 | ||||||||
| +10.23 | ||||||||
| +10.24 | ||||||||
| +10.25 | ||||||||
| +10.26 | ||||||||
| +10.27 | ||||||||
| +10.28 | ||||||||
| +10.29 | ||||||||
| +10.30 | ||||||||
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| +10.31 | ||||||||
| +10.32 | ||||||||
| +10.33 | ||||||||
| +10.34 | ||||||||
| +10.35 | ||||||||
| +10.36 | ||||||||
| 10.37 | ||||||||
| 10.38 | ||||||||
| 10.39 | ||||||||
| 10.40 | ||||||||
| +10.41 | ||||||||
| +10.42 | ||||||||
| +10.43 | ||||||||
| +10.44 | ||||||||
| +10.45 | ||||||||
| +10.46 | ||||||||
| +10.47 | ||||||||
| *21.1 | ||||||||
| *22.1 | ||||||||
158
| *23.1 | ||||||||
| *31.1 | ||||||||
| *31.2 | ||||||||
| **32.1 | ||||||||
| **32.2 | ||||||||
| *101.INS | XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||
| *101.SCH | Inline XBRL Taxonomy Extension Schema Document | |||||||
| *101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| *101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | |||||||
| *101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | |||||||
| *101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | |||||||
| *104 | The cover page of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, formatted in Inline XBRL (included with Exhibit 101 attachments). | |||||||
| * ** + | Filed herewith. Furnished herewith. Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. | |||||||
Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.
Item 16. Form 10-K Summary
None.
159
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 21, 2023.
| Valaris Limited (Registrant) | ||
By /s/ ANTON DIBOWITZ Anton Dibowitz Director, President and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
Signatures | Title | Date | ||||||||||||
/s/ CHRISTOPHER T. WEBER Christopher T. Weber | Senior Vice President and Chief Financial Officer (principal financial officer) | February 21, 2023 | ||||||||||||
/s/ GUNNAR ELIASSEN Gunnar Eliassen | Director | February 21, 2023 | ||||||||||||
/s/ DICK FAGERSTAL Dick Fagerstal | Director | February 21, 2023 | ||||||||||||
/s/ JOSEPH GOLDSCHMID Joseph Goldschmid | Director | February 21, 2023 | ||||||||||||
/s/ CATHERINE HUGHES Catherine Hughes | Director | February 21, 2023 | ||||||||||||
/s/ ELIZABETH D. LEYKUM Elizabeth D. Leykum | Chair of the Board | February 21, 2023 | ||||||||||||
/s/ DEEPAK MUNGANAHALLI Deepak Munganahalli | Director | February 21, 2023 | ||||||||||||
/s/ JAMES W. SWENT, III James W. Swent, III | Director | February 21, 2023 | ||||||||||||
/s/ COLLEEN W. GRABLE Colleen W. Grable | Vice President and Controller (principal accounting officer) | February 21, 2023 | ||||||||||||
160