EDGAR 10-K Filing

Company CIK: 314808
Filing Year: 2022
Filename: 314808_10-K_2022_0000314808-22-000011.json

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ITEM 1. BUSINESS
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. We currently own an offshore drilling rig fleet of 56 rigs, with drilling operations in almost every major offshore market across six continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 40 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.
Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning 14 countries. The markets in which we operate include the Gulf of Mexico, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.
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.
As we entered 2020, we expected the volatility that began with the oil price decline in 2014 to continue over the near-term with the expectation that long-term oil prices would remain at levels sufficient to support a continued gradual recovery in the demand for offshore drilling services. We were focused on opportunities to put our rigs to work, manage liquidity, extend our financial runway, and reduce debt as we sought to navigate the extended market downturn and improve our balance sheet. Recognizing our ability to maintain a sufficient level of liquidity to meet our financial obligations depended upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control, we had significant financial flexibility within our capital structure to support our liability management efforts. However, starting in early 2020, the COVID-19 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, leading to a supply glut. As a consequence, the price of Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. In response to dramatically reduced oil price expectations, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers, primarily in the second and third quarters of 2020, to cancel or shorten the duration of many of our drilling contracts, cancel future drilling programs and seek pricing and other contract concessions which led to material operating losses and liquidity constraints for us.
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 current and 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 2021 to nearly $80 per barrel by the end of the year and have subsequently increased to over $90 per barrel in early 2022. Increased oil prices are 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. Benign floater rig years awarded in 2021 were more than double the amount awarded in 2020. This increase in activity is particularly evident for drillships with several multi-year contracts awarded and a meaningful improvement in day rates for this class of assets. Jackup contracting activity also increased in 2021, but at a more modest pace than for floaters; however, demand for jackups did not decline as significantly in 2020 as it did for floaters. While the near-term outlook for the offshore drilling industry has improved, particularly for floaters, since the beginning of 2021, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.
Additionally, the full impact that the pandemic and the volatility of oil prices will have on our results of operations, financial condition, liquidity and cash flows is uncertain due to numerous factors, including the duration and severity of the pandemic, the continued effectiveness of the ongoing vaccine rollout, the general resumption of global economic activity along with the injection of substantial government monetary and fiscal stimulus and the sustainability of the improvements in oil prices and demand in the face of market volatility. To date, the COVID-19 pandemic has resulted in limited operational downtime. Our rigs have had to shut down operations while crews are tested and incremental sanitation protocols are implemented and while crew changes have been restricted as replacement crews are quarantined. We continue to incur additional personnel, housing and logistics costs in order to mitigate the potential impacts of COVID-19 to our operations. In limited instances, we have been reimbursed for these costs by our customers. Our operations and business may be subject to further economic disruptions as a result of the spread of COVID-19 among our workforce, the extension or imposition of further public health measures affecting supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties. There can be no assurance that these, or other issues caused by the COVID-19 pandemic, will not materially affect our ability to operate our rigs in the future.
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 9 - 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 included 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. Floaters, Jackups and ARO are also reportable segments.
We own and operate 56 rigs, 26 are located in the Middle East, Africa and Asia Pacific, 12 are located in North and South America and 18 are located in Europe as of December 31, 2021.
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 largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.”
Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. The terms of our drilling contracts can vary significantly, 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 (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) 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 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 limited 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, including certain cost increases due to changes in applicable law, from our customers through day rate adjustment or direct reimbursement.
In general, in a downturn in offshore drilling demand, contract awards are subject to an extremely competitive bidding process. The intense pressure on operating day rates 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 due to damage or failure of our equipment; 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.
Backlog Information
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for discussion on backlog information.
Drilling Contracts and Insurance Program
Our drilling contracts provide for varying levels of allocation of responsibility for liability between our customer and us for loss or damage to each party's property and third-party property, personal injuries and other claims arising out of our drilling operations. We also maintain insurance for these exposures to personal injuries, damage to or loss of property and certain business risks.
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 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. Accordingly, we retain the risk for windstorm damage to our drilling in the U.S. Gulf of Mexico. We do not currently carry insurance for loss of hire. Any such lack of reimbursement 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.
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.
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. This exclusion overrides other provisions in the contract that would otherwise limit our liability for ordinary negligence. 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, and 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.
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 eight months ended December 31, 2021 (Successor), our five largest customers accounted for 42% of consolidated revenues. BP, our only customer who accounts for 10% or more of consolidated revenues, accounted for 11% of consolidated revenues. During the four months ended April 30, 2021 (Predecessor), our five largest customers accounted for 45% of consolidated revenues. BP, our only customer who accounts for 10% or more of consolidated revenues, accounted for 14% 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. There are numerous competitors with significant resources in the offshore contract drilling industry.
Governmental Regulation and Environmental Matters
Our operations are affected by political initiatives and by laws and regulations that relate to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements. Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and 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 the costs associated with our offshore drilling 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. 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 natural resources below the rate that would otherwise be possible.
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, which may not be covered by contractual indemnification or insurance or for which indemnity is prohibited by applicable law 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 well-control incidents 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 the entire offshore drilling industry.
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, and other related legislation and regulations and 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 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.
As a result of the 2010 Macondo well incident, the United States Bureau of Safety and Environmental Enforcement ("BSEE") issued a drilling safety rule in 2012 that included requirements for the cementing of wells, well-control barriers, blowout preventers, well-control fluids, well completions, workovers and decommissioning operations. BSEE also issued regulations requiring operators to have safety and environmental management
systems ("SEMS") prior to conducting operations and requiring operators and contractors to agree on how the contractors will assist the operators in complying with the SEMS. In addition, in August 2012, BSEE issued an Interim Policy Document ("IPD") stating that it would begin issuing Incidents of Non-Compliance to contractors as well as operators for serious violations of BSEE regulations. Following federal court decisions successfully challenging the scope of BSEE’s jurisdiction over offshore contractors, this IPD has been removed from the list of IPDs on the BSEE website. If this judicial precedent stands, it may reduce regulatory and civil litigation liability exposures.
On July 28, 2016, 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. Specifically, the 2019 Well Control Rule addresses six areas of offshore operations: well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions were targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing unnecessary regulatory burden. 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 July 2017 the USCG issued proposed 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. Any such legislation or regulatory programs could also increase the cost of consuming oil, and thereby reduce demand for oil, 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.
Although the United States had withdrawn from the Paris Agreement in November 2020, the United States officially reentered the agreement in February 2021. Further, in November 2021, the Unites 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 likely 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 and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad. The latter executive order 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. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction
against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation challenging that aspect of the executive order is ongoing. On January 27, 2022, the United States District Court for the District of Columbia found that the Bureau of Ocean Energy Management’s failure to calculate the potential emissions from foreign oil consumption violated the agency’s approval of oil and gas leases in the Gulf of Mexico under the National Environmental Policy Act. The full impact of these federal actions, or any other future restrictions or prohibitions, remains unclear.
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 can be costly and could limit our operations."
Non-U.S. Operations
Revenues from non-U.S. operations were 87%, 81%, 83% and 85% of our total consolidated revenues during eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor), year-ended December 31, 2020 and 2019 (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 22, 2022:
Name Age Position
Anton Dibowitz 50 President and Chief Executive Officer
Darin Gibbins 40 Interim Chief Financial Officer and Vice President, Investor Relations and Treasurer
Gilles Luca 50 Senior Vice President - Chief Operating Officer
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. Previously, he served as an advisor of Seadrill Ltd. 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).
Darin Gibbins became the Interim Chief Financial Officer and Vice President, Investor Relations and Treasurer of Valaris in September 2021. Previously, he served as Vice President, Investor Relations and Treasurer of the Company since June 2020 and has also served as Vice President, Treasurer of the Company from April 2019 through June 2020. Prior to joining the Company, he spent over thirteen years at Rowan Companies plc, beginning in November 2006. At Rowan Companies plc, he most recently served as Vice President, FP&A and Treasurer from February 2017 to April 2019 and Treasurer & Director, Financial Planning from March 2016 through February 2017. Mr. Gibbins also worked as a Senior Consultant at Protiviti Inc. from August 2004 through November 2006. Mr. Gibbins is a graduate of the University of Texas at Austin, where he earned his Bachelor of Business Administration (BBA) in Finance with a minor in Accounting.
Gilles Luca joined Valaris in 1997 and was appointed to his current position of Senior Vice President - Chief Operating Officer in November 2019. Prior to his current position, Mr. Luca served as Senior Vice President - Western Hemisphere, Vice President - Business Development and Strategic Planning, Vice President - Brazil Business Unit and General Manager - Europe and Africa. He holds a Master's Degree in Petroleum Engineering from the French Petroleum Institute and a Bachelor in Civil Engineering from ESTP, Paris.
Employees
We employed approximately 4,900 personnel worldwide including contract employees, and approximately 3,400 personnel excluding contract employees, as of December 31, 2021. The majority of our personnel work on rig crews and are compensated on an hourly basis.
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 or furnish to the Securities and Exchange Commission ("SEC") in accordance with the Exchange Act are available on our website at www.valaris.com/investors. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. These reports also are available in print without charge by contacting our Investor Relations Department as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC. The information contained on our website is not included as part of, or incorporated by reference into, this report.
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 effects of the COVID-19 pandemic have adversely impacted, and could continue to adversely impact, our financial condition and results of operations.
•The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by oil and natural gas prices.
•The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.
•Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.
•Our business will be adversely affected if we are unable to secure contracts on economically favorable terms.
•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.
•We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.
•The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could adversely affect us.
•Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns.
•We have historically made significant expenditures to 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 capital 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 ARO, which depends on a single customer for its income and accounts receivable.
•Our information technology systems, including rig operating systems, are subject to cybersecurity risks.
•We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage cannot protect us against all of the risks and hazards we face.
•The potential for hurricane related windstorm damage or liabilities could result in uninsured 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.
•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 part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
•We may incur impairments as a result of future declines in demand for offshore drilling rigs.
•Our long-term contracts are subject to the risk of cost increases, which could adversely affect our profitability.
•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 operating and financial restrictions that restrict our business and financing activities.
•On April 30, 2021, we emerged from bankruptcy, which may adversely affect our business and relationships.
•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.
•Our historical financial information will not be indicative of future financial performance as a result of the implementation of the plan of reorganization and the transactions contemplated thereby, as well as our application of fresh start accounting following emergence.
•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.
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.
•Increased scrutiny from stakeholders and others regarding our ESG practices and reporting responsibilities could result in additional costs or risks and adversely impact our business and reputation.
Regulatory, Legal and Tax Risks
•Failure to comply with anti-bribery statutes could result in fines, criminal penalties, drilling contract terminations and have an adverse effect on our business.
•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.
•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.
•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.
•Legislation enacted in Bermuda as to Economic Substance may affect our operations.
•The impact of the U.K.'s withdrawal from the E.U. on economic conditions may affect our business.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Risks Related to Our Business, Operations, Indebtedness and Market Conditions
The effects of the COVID-19 pandemic have adversely impacted, and could continue to adversely impact, our financial condition and results of operations.
Beginning in March 2020, the COVID-19 pandemic and related public health measures implemented by governments worldwide negatively impacted the global macroeconomic environment and resulted in a sharp decline in global oil demand and prices. In response to reduced oil price expectations, our customers significantly lowered their capital expenditure plans. As of February 2022, crude oil prices and demand have recovered from the historic lows seen in the first half of 2020. While the near-term outlook for the offshore drilling industry has improved, particularly for floaters, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.
To date, there have been various impacts from the pandemic and the resultant drop in oil prices, including contract cancellations and the delay or cancellation of drilling programs by operators, contract concessions, stacking rigs, inability to change crews due to travel restrictions, and workforce reductions. Our operations and business may be subject to further disruptions as a result of the spread of COVID-19 and its variants among our workforce, the extension or imposition of further public health measures affecting our supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties. In addition, government vaccine mandates and the vaccination requirements of our customers could affect our ability to retain offshore crews or require us to increase wages to retain qualified personnel for our drilling rigs.
The COVID-19 pandemic could continue to adversely impact the supply chain for equipment or services needed for operations, including as a result of mandatory shutdowns and other pandemic-related measures implemented in locations where such equipment or services are manufactured or distributed. In addition to experiencing increased shipping costs, we could also see significant disruptions of the operations to our logistics and service providers.
Oil prices may continue to be volatile as a result of production instability, ongoing COVID-19 outbreaks, including variant strains of COVID-19, the implementation of vaccination programs and the related impact on overall economic activity, global inflation, changes in oil inventories, industry demand and global and national economic performance.
The success of our business largely 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 largely 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 potential changes in these prices, significantly affect the level of drilling activity. Historically, when operator capital spending declines, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs may be exacerbated by the entry of newbuild rigs into the market. Oil and natural gas prices declined significantly from prices in excess of $100 since mid-2014, causing operators to reduce capital spending and cancel or defer existing programs, substantially reducing the opportunities for new drilling contracts. While market conditions have recently improved, we have not yet experienced an extended period of sustained oil and natural gas prices. The lack of a sustained and stable recovery of oil and natural gas prices, further price reductions or volatility in 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 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,
•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,
•oil and natural gas supply and demand, which is affected by worldwide economic activity and population growth,
•expectations regarding future energy prices,
•the ability of the Organization of Petroleum Exporting Countries ("OPEC") to reach further agreements to set and maintain production levels and pricing and to implement existing and future agreements,
•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,
•advances in exploration and development technology,
•costs associated with exploring for, developing, producing and delivering oil and natural gas,
•the rate of discovery of new oil and gas reserves and the rate of decline of existing oil and gas reserves,
•investors reducing, or ceasing to provide, funding to the oil and 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 (such as the current moratorium on oil and gas leasing and permitting in federal lands and waters, which is currently subject to ongoing litigation),
•the development and exploitation of alternative fuels or energy sources and increased demand for electric-powered vehicles,
•disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof,
•natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills, and
•the worldwide military or political environment, including the 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.
The agreements of OPEC and certain non-OPEC countries to freeze and/or cut production may not be fully realized. The lack of actual production cuts or freezes, or the perceived risk that OPEC countries may not comply with such agreements, may result in depressed commodity prices for an extended period of time.
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 expenditure for exploration and production for a variety of reasons, including their expectations for future oil prices, extended periods of price volatility and their lack of success in exploration efforts. Advances in onshore exploration and development technologies, particularly with respect to onshore shale, could also result in our customers allocating more of their capital expenditure budgets to onshore exploration and production activities and less to offshore activities. In addition, some of our customers are transitioning their businesses to renewable energy projects and away from oil and natural gas exploration and production, which could result in reduced capital spending by such customers on oil and natural gas projects and in turn reduced demand for our services. These factors could cause our revenues and profits to decline, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decline in day rates or utilization of our drilling rigs could materially reduce our revenues and profitability. 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 historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.
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 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 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, coupled with the prolonged oversupply of drilling rigs, could 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, 2022, our contract backlog was approximately $2.4 billion, which represents an increase of $1.4 billion to the reported backlog of $1.0 billion as of December 31, 2020. 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. 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 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 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 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, "force majeure" events, 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. 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. 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. 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 may have a material adverse effect on our financial position, operating results or cash flows.
Our business will be 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 for 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 adversely affect our revenues and profitability. 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.
Certain of our customers are subject to liquidity risk and such risk 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 from our customers. Our drilling contracts also 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-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 blow-outs 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 assume their responsibility and honor their indemnity 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.
We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.
In market downturns, our customers may not be able to honor the terms of existing contracts, may terminate contracts even where there may be onerous termination fees, may seek to void or otherwise repudiate our contracts including by claiming we have breached the contract, or may seek to renegotiate contract day rates and terms. Our drilling contracts may be subject to termination without cause or termination for convenience upon notice by the customer. In certain cases, our contracts require the customer to pay an early termination fee in the event of an early termination for convenience (without cause), exercisable upon advance notice to us. Such payment 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. Certain contracts may permit termination by the customer without an early termination fee. Furthermore, financially distressed customers may seek to negotiate reduced termination fees as part of a restructuring package.
Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.
If a customer cancels a contract or if we terminate a contract due to the customer’s breach and, in either case, we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or suspended for an extended period of time or renegotiated, it could materially and adversely affect our financial position, operating results or cash flows.
The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could adversely affect us.
We provide our services to major international, government-owned and independent oil and gas companies. During the eight months ended December 31, 2021 (Successor), our five largest customers accounted for 42% of consolidated revenues, with our largest customer representing 11% of our consolidated revenues and a significant percentage of our operating cash flows. During the four months ended April 30, 2021 (Predecessor), our five largest customers accounted for 45% of consolidated revenues. BP, our only customer who accounts for 10% or more of consolidated revenues, accounted for 14% of consolidated revenues. 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 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 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 results of operations or financial condition will be negatively impacted.
Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on 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. During 2022, we currently anticipate that we will be reactivating four floater rigs. These drilling rigs were previously stacked, and expenditures will be required 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.
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 COVID-19 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.
We have historically made substantial 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 capital expenditures to maintain our competitiveness.
We have historically made 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 and maritime self-regulatory organization 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, such as equipping the VALARIS DS-11 with 20,000 psi well-control 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 some, or all, of our assets as collateral. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business and on our financial position, operating results or cash flows.
Failure to recruit and retain skilled personnel could 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. Competition for the labor required for drilling operations and construction projects has recently intensified as the number of active drilling rigs has increased, 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. The recent prolonged industry downturn and reductions in offshore personnel wages further reduced the number of qualified personnel available. As demand for our services has increased, competition for labor has intensified, resulting in higher wages in order to retain qualified offshore personnel. The increase in wages causes 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. In addition, due to the specialized skills and qualifications required to operate an offshore drilling rig, 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.
In an environment where competition for labor is intense, we may be required to increase existing levels of compensation to retain our skilled workforce, especially if our competitors raise their wage rates. 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.
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 have an adverse effect on our financial condition, operating results or cash flows.
We have undertaken a shared service center initiative pursuant to which we are outsourcing 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 initiative. As part of this initiative, 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 have an adverse effect on our financial condition, operating results or cash flows.
We may not realize the expected benefits of ARO, which depends on a single customer for its income and accounts receivable, and our inability to realize such benefits may introduce additional risks to our business.
Our 50/50 joint venture with Saudi Aramco, 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. The first rig is expected to be delivered in the fourth quarter of 2022, and the second rig is expected either late in the fourth quarter of 2022 or in the first quarter of 2023. ARO is expected to place orders for two additional newbuild jackups in 2022. There can be no assurance that the new jackup rigs will begin operations as anticipated or we will realize the expected return on our investment. We may also experience difficulty in jointly managing the venture. 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. Any required capital contributions we make will negatively impact our liquidity position and financial condition.
In 2017 and 2018, Rowan Companies Limited (formerly Rowan Companies plc) ("Rowan") issued 10-year shareholder notes receivables to ARO, which are governed by the laws of Saudi Arabia, earn interest based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent and mature during 2027 and 2028. In the event of a dispute with ARO over the repayment of the long-term notes receivable, 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 long-term notes receivable is subject to the consent of Saudi Aramco and that the long-term notes receivable are governed by the laws of Saudi Arabia and we are limited to the remedies available under Saudi law.
As a result of these risks, it may take longer than expected for us to realize the expected returns from 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 adversely impact our operating results or financial condition.
ARO’s income and accounts receivable are concentrated with one customer. 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 adversely impact our operating results or financial condition.
ARO, as 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 have a material adverse effect on our financial condition and results of operations. Additionally, in order to establish or preserve our relationship with our joint venture partner we may agree to risks 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.
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 adversely affect our financial position, operating results or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our systems, which to date have not had a material impact on our operations; however, there can be no assurance that such impacts will not be material in the future. 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.
We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage cannot protect us against all of the risks and hazards we face, including those specific to offshore operations.
Our operations are subject to hazards inherent in the offshore drilling industry, such as blow-outs, 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. 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 third-parties or customers or prosecution by governmental authorities, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as punch-throughs, capsizing, sinking, grounding, mooring failures, collision, damage from severe weather and marine life infestations. We have safety processes in place in an effort to mitigate the risks of the above hazards occurring, but our processes may not be effective to fully eliminate these risks or may not be followed. Additionally, a cyber-attack or other security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems and/or loss of business information, which could result in an adverse impact to our business. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well-control and subsurface risks. For example, most of our drilling contracts include limitations in the form of liability caps 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.
We generally identify and assess the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost, availability and reliability of insurance coverage, the requirements of our customer contracts and applicable legal requirements. Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, it is not possible to obtain insurance against all potential risks and hazards, nor may it always be possible to maintain the same levels and types of coverage that we have maintained in the past. Cyclical insurance market conditions, major insurance losses, changes in the perceived risk exposure, new regulations, changes in our financial position and/or our operating conditions could cause insurance companies to increase our premiums and deductibles or limit our coverage amounts.
As a result of climate change activism or increased costs to insurance companies due to regulatory, geopolitical or other developments, insurance companies that have historically participated in underwriting energy-related risks 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 energy-related insurance claims or natural catastrophes such as floods, windstorms or earthquakes may result in withdrawal of insurance capacity and increasing premiums to energy industry companies.
Furthermore, our insurance carriers may interpret our insurance policies such that they do not provide coverage for all of our losses. Our insurance policies also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, certain loss or damage to property onboard our drilling rigs, loss of hire and losses relating to terrorist acts or strikes and some cyber events.
If we are unable to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable, we may choose to forgo insurance coverage and retain the associated risk of loss or damage.
If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity (or if our contractual indemnity is not enforceable under applicable law or our clients are unable to meet their indemnification obligation), it could adversely affect our financial position, operating results or cash flows.
The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season.
Certain areas of the world, such as the U.S. Gulf of Mexico experience hurricanes or similar extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the U.S. Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms. We had 10 rigs in the U.S. Gulf of Mexico as of December 31, 2021. Damage caused by high winds and turbulent seas could result in personal injury, rig loss or damage, termination of drilling contracts for lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the U.S. Gulf of Mexico have been impacted by hurricanes in the past, including the total loss of drilling rigs, with associated losses of contract revenues and potential liabilities.
Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the U.S. Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the U.S. Gulf of Mexico and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to U.S. Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for any potential liabilities to third-parties associated with property damage, personal injury or death and environmental liabilities, as well as coverage for removal of wreckage and debris associated with hurricane losses. It is likely that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will continue into the foreseeable future.
We have not purchased windstorm insurance for hull and machinery losses to our drilling rigs arising from windstorm damage in the U.S. Gulf of Mexico due to the significant premium, high deductible and limited coverage for windstorm damage. We believe it is no longer customary for drilling contractors with similar size and fleet composition to purchase windstorm insurance for drilling rigs in the U.S. Gulf of Mexico for the aforementioned reasons. Accordingly, we have retained the risk of loss or damage for our drilling rigs arising from windstorm damage in the U.S. Gulf of Mexico.
We have established operational procedures designed to mitigate risk to our drilling rigs in the U.S. Gulf of Mexico during hurricane season, and these procedures may, on occasion, result in a decision to decline to operate on a customer-designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing drilling rig operations in the U.S. Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm-related risks, may result in a significant reduction in the utilization of our jackups in the U.S. Gulf of Mexico.
Any retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with U.S. Gulf of Mexico tropical storms or hurricanes may have a material adverse effect on our financial position, operating results or cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of these storms or hurricanes.
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.
Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses. Military action by the United States 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 companies such as ours. 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 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. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could have a material adverse effect on 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 15 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.
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 revenues 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 business, 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 increase our operating costs, decrease our revenues and adversely impact our operations.
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. The business environment since the 2014 downturn as well as industry consolidation has reduced 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 unscheduled operational downtime, or such delays could cause 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.
We may incur impairments as a result of future declines in demand for offshore drilling rigs.
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be idle or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods in which rig supply exceeds rig demand, competition may force us to contract our rigs at or near cash break-even rates for extended periods of time.
Since 2014 Predecessor has recorded pre-tax, non-cash losses on impairment of long-lived assets totaling $9.8 billion, including $756.5 million aggregate pre-tax, non-cash impairments with respect to certain floaters, jackups and spare equipment, which Predecessor recorded during the first quarter of 2021. See "Note 8 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
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 increases. 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.
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. The First Lien Notes contain payment-in-kind interest provisions, which reduce the cash needed to pay interest while increasing the principal amount of First Lien Notes that ultimately must be retired with a cash payment. Our business may not generate sufficient cash flow from operations in the future, which could result in our being unable to repay indebtedness or to fund other liquidity needs. A range of economic, competitive, business and industry factors will affect our future financial performance, and many of these factors, such as the economic and financial 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 pay the amounts due under our debt.
The indenture dated April 30, 2021 (the "Indenture") governing the First Lien Notes contains operating and financial restrictions that restrict our business and financing activities and could limit our growth.
The primary restrictive covenants contained in the Indenture governing the First Lien Notes limit our ability to, among other things:
•incur 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 liens; and
•pay dividends or repurchase Common Shares.
As a result of these restrictive covenants, we will be limited in 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 operating restrictions, as well as the other financial 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 have a material adverse effect on our business, financial condition and results of operations.
On April 30, 2021, we emerged from bankruptcy, which may adversely affect our business and relationships.
Our having filed for bankruptcy and our emergence from the Chapter 11 Cases on April 30, 2021 may adversely affect our business and relationships with our vendors, suppliers, service providers, customers, employees and other third-parties. Many risks exist as a result of the Chapter 11 Cases and our emergence, including the following:
•we may have difficulty obtaining acceptable and sufficient financing to execute our business plan;
•key suppliers, vendors and customers may, among other things, renegotiate the terms of their agreements with us, attempt to terminate their relationship with us or require financial assurances from us;
•our ability to renew existing contracts and obtain new contracts on reasonably acceptable terms and conditions may be adversely affected;
•our ability to attract, motivate and retain key employees and executives may be adversely affected; and
•competitors may take business away from us, and our ability to compete for new business and attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
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.
Our historical financial information will not be indicative of future financial performance as a result of the implementation of the plan of reorganization and the related transactions, as well as our application of fresh start accounting following emergence.
Our capital structure was significantly impacted by the plan of reorganization. Under fresh start accounting rules that we applied on the Effective Date, assets and liabilities were adjusted to fair values and our accumulated deficit was reset to zero. Accordingly, as a result of the application of fresh start accounting, our financial condition and results of operations following emergence from the Chapter 11 Cases are not comparable to the financial condition and results of operations reflected in our historical financial statements on or prior to the Effective Date.
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 75,000,000 Common Shares and 5,645,161 warrants to purchase 5,645,161 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 8,960,573 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 an adverse effect on the market for our Common Shares, including the price that an investor could obtain for their Common Shares.
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. In addition, 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 COP26 UN Climate Change Conference in November 2021.
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 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 would have a material adverse impact on our business.
In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be negatively 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 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 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 could 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 and reporting responsibilities, could result in additional costs or risks and adversely impact our business and reputation.
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, 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 and goals. We published our 2020 Sustainability Report in September 2021. Our disclosures on these matters, a failure
to meet these goals or evolving stakeholder expectations for ESG practices and reporting may potentially harm our reputation and impact employee retention, customer relationships and access to capital. 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.
Regulatory, Legal and Tax Risks
Failure to comply with anti-bribery statutes could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.
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.
Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws by us, our affiliated entities or their 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 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 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 adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs. Increases in regulatory requirements could significantly increase our costs. 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 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 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”) may 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 are currently treated as 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 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. 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.
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 cause a material adverse effect on 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 cause a material adverse effect on our financial position, operating results or cash flows.
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 United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States 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 United States, 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 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 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 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.
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 adversely affect our results of operations and financial condition. 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 revenue, earnings and operating cash flows could be 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 87%, 81%, 83% and 85% of our total consolidated revenues during eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor), year-ended December 31, 2020 and 2019 (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,
•changes in monetary policies,
•uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America, Southeastern Asia 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 cause a material adverse effect on 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.
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. Although the outcome of such assessments cannot be predicted with certainty, unfavorable outcomes could have a material adverse effect on our liquidity.
Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have enacted exchange controls. Generally, we have contractually mitigated these risks by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting our acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, not all of our contracts contain these terms and there is no assurance that our contracts will contain such terms in the future.
A portion of the costs and expenditures incurred by our non-U.S. operations, including certain capital expenditures, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We have historically used foreign currency forward contracts to reduce this exposure in certain cases. However, a relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.
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 gas industry in their countries. In some areas of the world, government activity has 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 have a material adverse effect on our future operations.
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 United States, 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.
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 employees, contractors 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 have a material adverse effect on our financial position, operating results or cash flows.
Legislation enacted in Bermuda as to Economic Substance may affect our operations.
Pursuant to the Economic Substance Act 2018 (as amended) of Bermuda (the “ES Act”) that came into force on January 1, 2019, a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda (“non-resident entity”) that carries on as a business any one or more of the “relevant
activities” referred to in the ES Act must comply with economic substance requirements. The ES 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, leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities. The ES Act could affect the manner in which we operate our business, which could adversely affect our business, financial condition and results of operations.
The U.K.'s withdrawal from the E.U. may have a negative effect on economic conditions, financial markets and our business.
On April 27, 2021, the European Parliament approved the agreement on the terms of the U.K.’s future relationship with the E.U. (the “Trade and Cooperation Agreement”), which provides for zero tariffs and quotas on the movement of goods between the U.K. and the E.U. (provided they comply with the parties’ agreed rules of origin) and seeks to minimize trade disruption arising from technical and administrative barriers to trade. However, there can be no guarantee that the ongoing implementation of the Trade and Cooperation Agreement will not lead to significant increased costs and supply chain disruption for our business and the businesses of our U.K. customers and suppliers. Any incremental costs incurred by our U.K. suppliers may be passed on to us and any supply chain disruption experienced by our U.K. customers or suppliers may in turn disrupt our own operations.
The U.K.’s withdrawal from the E.U. has also given rise to calls for the governments of other E.U. member states to consider withdrawal, while the U.K.’s withdrawal negotiation process has increased the risk of the possibility of a further referendum concerning Scotland’s independence from the rest of the U.K. These developments, or the perception that any of them could occur, have had and may continue to have a material adverse effect on global, regional and/or national economic conditions and the stability of global financial markets, and may significantly reduce global market liquidity.
The implementation of the Trade and Cooperation Agreement and/or any subsequent divergence of the law applicable in the U.K. and the E.U. could depress economic activity, result in changes to currency exchange rates, taxes, import/export regulations, laws and other regulatory matters, and/or restrict our access to capital and the free movement of our employees, which could have a material adverse effect on our financial position, operating results or cash flows. Approximately 22% and 19% of our total revenues were generated in the U.K. for the eight months ended December 31, 2021 (Successor) and four months ended April 30, 2021 (Predecessor), respectively.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
Contract Drilling Fleet
The following table provides certain information about the rigs in our drilling fleet as of February 21, 2022:
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' Spain Under reactivation(3)
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' Spain Under reactivation(3)
VALARIS DS-10 Drillship 2015 Dynamically Positioned 12,000'/40,000' Namibia Under contract
VALARIS DS-11 Drillship 2013 Dynamically Positioned 12,000'/40,000' Spain Preservation stacked(1)(4)
VALARIS DS-12 Drillship 2013 Dynamically Positioned 12,000'/40,000' Angola Under contract
VALARIS DS-13 Drillship Under construction Dynamically Positioned 12,000'/40,000' South Korea Option(2)
VALARIS DS-14 Drillship Under construction 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 reactivation(3)
VALARIS DS-17 Drillship 2014 Dynamically Positioned 12,000'/40,000' Spain Preservation stacked(1)
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' Gulf of 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 36 Jackup 1981/2011 MLT 116-C 300'/25,000' Saudi Arabia Leased to ARO drilling
VALARIS 54 Jackup 1982/2004 F&G L-780 MOD II-C 300'/25,000' Saudi Arabia Under contract
VALARIS 67 Jackup 1976/2005 MLT 84-CE 350'/30,000' Indonesia Preservation stacked(1)
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 113 Jackup 2012 Baker Marine Pacific Class 400 400'/30,000' Philippines Preservation stacked(1)
Rig Name Rig Type Year Built/
Rebuilt Design Maximum
Water Depth/
Drilling Depth Location Status
Jackups
(Continued)
VALARIS 114 Jackup 2012 Baker Marine Pacific Class 400 400'/30,000' Philippines Preservation stacked(1)
VALARIS 115 Jackup 2013 Baker Marine Pacific Class 400 400'/30,000' Thailand 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 Mexico 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
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 Under contract
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' Norway Under contract
VALARIS Stavanger Jackup 2011 KEFLS N Class 400'/35,000' Norway Under contract
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)Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14. On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy. The amendments 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 rigs on or before December 31, 2023. Under the amended agreements, the purchase price for the rigs is estimated to be approximately $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. The amended agreements removed any parent company guarantee.
(3)Rig being reactivated for a firm contract.
(4)Rig preservation stacked but has a firm contract that commences in July 2024. In February 2022, the customer decided not to sanction and therefore withdraw from the project associated with this contract. As of the date hereof, the customer has not terminated the contract, but may do so upon the payment of an early termination fee should the project not receive a final investment decision (FID). The project has not received FID. We are in discussions with the customer and its partner on the project to determine next steps.
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 a computer-controlled propeller 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 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.
As of February 21, 2022, we owned all rigs in our fleet. We also manage the drilling operations for two platform rigs owned by a third-party.
We lease office space in the UK (London & Aberdeen), the USA (Houston), Australia, Indonesia, Mexico, Brazil, Nigeria, The Netherlands, UAE (Dubai), Saudi Arabia, Thailand, and Norway. We own offices and other facilities in Louisiana, Angola, and Brazil.

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ITEM 3. LEGAL PROCEEDINGS
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 $0.4 million liability related to these matters was included in Accrued liabilities and other on our Consolidated Balance Sheet as of December 31, 2021 included in "Item 8. Financial Statements and Supplementary Data."
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 DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 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 75,000,000 Common Shares and 5,645,161 Warrants and has listed the Common Shares and the Warrants on The New York Stock Exchange under the symbols “VAL” and “VAL WS”, respectively.
Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 208 shareholders of record on February 1, 2022.
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.
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 Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda 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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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
Our Business
We are a leading provider of offshore contract drilling services to the international oil and gas industry. We currently own an offshore drilling rig fleet of 56 rigs, with drilling operations in almost every major offshore market across six continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 40 jackup rigs and a 50% equity interest in ARO, our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.
Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning 14 countries. The markets in which we operate include the Gulf of Mexico, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.
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 9 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" 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 the Warrants to purchase Common Shares. See “Note 11 - 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.
As we entered 2020, we expected the volatility that began with the oil price decline in 2014 to continue over the near-term with the expectation that long-term oil prices would remain at levels sufficient to support a continued gradual recovery in the demand for offshore drilling services. We were focused on opportunities to put our rigs to work, manage liquidity, extend our financial runway, and reduce debt as we sought to navigate the extended market downturn and improve our balance sheet. Recognizing our ability to maintain a sufficient level of liquidity to meet our financial obligations depended upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control, we had significant financial flexibility within our capital structure to support our liability management efforts. However, starting in early 2020, the COVID-19 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, leading to a supply glut. As a consequence, the price of Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. In response to dramatically reduced oil price expectations, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers, primarily in the second and third quarters of 2020, to cancel or shorten the duration of many of our drilling contracts, cancel future drilling programs and seek pricing and other contract concessions which led to material operating losses and liquidity constraints for us.
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 current and expected liquidity position and financial runway and led to the filing of the Chapter 11 Cases.
In 2021, Brent crude oil prices increased from approximately $50 per barrel at the beginning of 2021 to nearly $80 per barrel by the end of the year and have subsequently increased to over $90 per barrel in early 2022. Increased oil prices are 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. Benign floater rig years awarded in 2021 were more than double the amount awarded in 2020. This increase in activity is particularly evident for drillships with several multi-year contracts awarded and a meaningful improvement in day rates for this class of assets. Jackup contracting activity also increased in 2021, but at a more modest pace than for floaters; however, demand for jackups did not decline as significantly in 2020 as it did for floaters. While the near-term outlook for the offshore drilling industry has improved, particularly for floaters, since the beginning of 2021, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.
Additionally, the full impact that the pandemic and the volatility of oil prices will have on our results of operations, financial condition, liquidity and cash flows is uncertain due to numerous factors, including the duration and severity of the pandemic, the continued effectiveness of the ongoing vaccine rollout, the general resumption of global economic activity along with the injection of substantial government monetary and fiscal stimulus and the sustainability of the improvements in oil prices and demand in the face of market volatility. To date, the COVID-19 pandemic has resulted in limited operational downtime. Our rigs have had to shut down operations while crews are tested and incremental sanitation protocols are implemented and while crew changes have been restricted as replacement crews are quarantined. We continue to incur additional personnel, housing and logistics costs in order to mitigate the potential impacts of COVID-19 to our operations. In limited instances, we have been reimbursed for these costs by our customers. Our operations and business may be subject to further economic disruptions as a result of the spread of COVID-19 among our workforce, the extension or imposition of further public health measures affecting supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties. There can be no assurance that these, or other issues caused by the COVID-19 pandemic, will not materially affect our ability to operate our rigs in the future.
Backlog
Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and is calculated by multiplying the contracted 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.
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 Condensed 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 6 - 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, 2022 and December 31, 2020 (in millions):
2021 2020
Floaters (1)
$ 1,665.3 $ 163.7
Jackups 643.0 737.6
Other(2)
135.6 140.1
Total $ 2,443.9 $ 1,041.4
ARO $ 1,501.1 $ 347.5
(1)Approximately $428 million of backlog as of February 21, 2022 is attributable to our contract awarded to VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S. Gulf of Mexico expected to commence in mid-2024. In February 2022, the customer decided not to sanction and therefore withdraw from the project associated with this contract. As of the date hereof, the customer has not terminated the contract, but may do so upon the payment of an early termination fee should the project not receive a final investment decision (FID). The project has not received FID. We are in discussions with the customer and its partner on the project to determine next steps.
(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.
The increase in our backlog of $1.4 billion is due to recent contract awards and contract extensions, partially offset by 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 $1.2 billion is primarily due to contracts awarded to seven ARO owned rigs during 2021 and four rigs leased from us to ARO, partially offset by revenues realized.
The following table summarizes our and ARO's contract backlog of business as of February 21, 2022 and the periods in which revenues are expected to be realized (in millions):
2022 2023 2024
and Beyond Total
Floaters $ 506.3 $ 454.2 $ 704.8 $ 1,665.3
Jackups 469.2 153.3 20.5 643.0
Other 46.0 45.0 44.6 135.6
Total $ 1,021.5 $ 652.5 $ 769.9 $ 2,443.9
ARO $ 375.2 $ 394.8 $ 731.1 $ 1,501.1
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.
See "Item 1A. Risk Factors - Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future, which may have a material adverse effect on our financial position, results of operations and cash flows” and “Item 1A. Risk Factors - We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.”
BUSINESS ENVIRONMENT
Floaters
Limited demand and excess supply continue to affect our floater fleet. Floater demand declined materially in March and April 2020, as our customers reduced capital expenditures particularly for capital-intensive, long-lead deepwater projects in the wake of oil price declines from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. This caused our customers, primarily in the second and third quarters of 2020, to cancel or delay drilling programs, to terminate drilling contracts and to request contract concessions. As discussed above, the more constructive oil price environment led to an improvement in contracting and tendering activity in 2021 as compared to 2020. However, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.
Our backlog for our floater segment was $1.7 billion (including approximately $428 million for the VALARIS DS-11 discussed above) and $163.7 million as of February 21, 2022 and December 31, 2020, respectively. The increase in our backlog was due to new contract awards and contract extensions, partially offset by revenues realized. A majority of these awards were executed at the end of 2021 for contracts expected to commence in 2022. As a result, we expect utilization and day rates to improve upon those of 2020 and 2021.
Utilization for our floaters was 27% during the year ended December 31, 2021 compared to 26% during the year ended December 31, 2020. Average day rates were approximately $193,000 and $192,000 during the years ended December 31, 2021 and 2020, respectively.
Globally, there are 20 newbuild drillships and benign environment semisubmersible rigs reported to be under construction, of which 6 are scheduled to be delivered before the end of 2022. Most newbuild floaters are uncontracted. Several newbuild deliveries have been delayed into future years, and more uncontracted newbuilds may be delayed or cancelled.
Drilling contractors have retired 134 benign environment floaters since the beginning of 2014. Seven benign environment floaters older than 20 years of age are currently idle, five additional benign environment floaters older than 20 years have contracts that will expire within six months without follow-on work, and there are a further 13 benign environment floaters that have been stacked for more than three years. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify some of these aging rigs may prove cost prohibitive. Drilling contractors will likely elect to scrap or cold-stack a portion of these rigs.
Continued improvements in demand and/or reductions in supply are necessary to maintain the improving utilization and day rate trajectory.
Jackups
During 2020, demand for jackups declined in light of increased market uncertainty. This caused our customers, primarily in the second and third quarters of 2020, to cancel or delay drilling programs, to terminate drilling contracts and to request contract concessions. We have observed a slight increase in customer tendering activity for jackups that commenced in the latter part of 2020. However, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.
Our backlog for our jackup segment was $643.0 million and $737.6 million as of February 21, 2022 and December 31, 2020, respectively. The decrease in our backlog was due to customer contract cancellations, customer concessions and revenues realized, partially offset by the addition of backlog from new contract awards and contract extensions.
Utilization for our jackups was 54% during the years ended December 31, 2021 and 2020. Average day rates were approximately $95,000 during the year ended December 31, 2021 compared to approximately $86,000 during the year ended December 31, 2020.
Globally, there are 29 newbuild jackup rigs reported to be under construction, of which 18 are scheduled to be delivered before the end of 2022. Most newbuild jackups are uncontracted. Over the past year, some jackup orders have been cancelled, and many newbuild jackups have been delayed. We expect that scheduled jackup deliveries will continue to be delayed until more rigs are contracted.
Drilling contractors have retired 161 jackups since the beginning of the downturn. There are 63 jackups older than 30 years which are idle, 21 jackups that are 30 years or older have contracts expiring within the next six months without follow-on work, and there are a further 15 jackups that have been stacked for more than three years. Expenditures required to re-certify some of these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs. We expect jackup scrapping and cold-stacking to continue in 2022.
Improvements in demand and/or reductions in supply will be necessary before meaningful and sustained increases in utilization and day rates are realized.
RESULTS OF OPERATIONS
In analyzing our results of operations, we are not able to compare the results of operations for the four-month period ended April 30, 2021 (the “2021 Predecessor Period”) to any of the previous periods reported in the consolidated financial statements, and we do not believe reviewing this period in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. With the exception of certain one-time charges as separately described below, we believe that the discussion of our results of operations for the eight months ended December 31, 2021 (the “Successor Period”) combined with the 2021 Predecessor Period provides a more meaningful comparison to the year ended December 31, 2020 and is more useful in understanding operational trends. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable SEC rules, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.
The following table summarizes our Consolidated Results of Operations (in millions):
Successor Predecessor Combined (Non-GAAP) Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Revenues $ 835.0 $ 397.4 $ 1,232.4 $ 1,427.2 $ 2,053.2
Operating expenses
Contract drilling (exclusive of depreciation) 728.7 343.8 1,072.5 1,470.4 1,807.8
Loss on impairment - 756.5 756.5 3,646.2 104.0
Depreciation 66.1 159.6 225.7 540.8 609.7
General and administrative 58.2 30.7 88.9 214.6 188.9
Total operating expenses 853.0 1,290.6 2,143.6 5,872.0 2,710.4
Other operating income - - - 118.1 -
Equity in earnings (losses) of ARO 6.1 3.1 9.2 (7.8) (12.6)
Operating loss (11.9) (890.1) (902.0) (4,334.5) (669.8)
Other income (expense), net 20.1 (3,557.5) (3,537.4) (782.5) 606.0
Provision (benefit) for income taxes 37.4 16.2 53.6 (259.4) 128.4
Net loss (29.2) (4,463.8) (4,493.0) (4,857.6) (192.2)
Net (income) loss attributable to noncontrolling interests (3.8) (3.2) (7.0) 2.1 (5.8)
Net loss attributable to Valaris $ (33.0) $ (4,467.0) $ (4,500.0) $ (4,855.5) $ (198.0)
Overview
Year Ended December 31, 2021
Revenues declined $194.8 million, or 13.6%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year. This decline is primarily due to $199.8 million resulting from fewer operating days in the current year, $46.3 million due to termination fees received for certain rigs in the prior year period and $19.0 million due to lower revenues earned under an agreement to provide certain Rowan employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement"). See "Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. This decline was partially offset by a $111.2 million increase in revenue for certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.
Contract drilling expense declined $397.9 million, or 27.1%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year. This decline is primarily due to $279.8 million of lower costs for idle rigs, $77.8 million from rigs sold between the comparative periods, a $26.5 million reduction in costs related to contract preparation projects in 2020 and approximately $40.0 million of lower costs due to spend control efforts. Additionally, there was a decline of $19.0 million related to the Secondment Agreement with ARO as almost all remaining seconded employees became employees of ARO during the second quarter of 2020. This decrease was partially offset by an increase of $84.4 million in reactivation costs for certain rigs stacked in the prior year.
During the 2021 Predecessor Period, we recorded non-cash losses on impairment totaling $756.5 million with respect to certain assets in our fleet. During the first and second quarters of 2020 (Predecessor), we recorded non-cash losses on impairment totaling $3.6 billion, with respect to assets in our fleet, primarily due to the adverse change in the current and anticipated market for these assets. See "Note 8 - Property and Equipment" for additional information.
Depreciation expense declined $315.1 million, or 58.3%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to lower depreciation resulting from the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to the impairment of certain non-core assets in 2020 and the first quarter of 2021. Certain of the assets impaired in the first and second quarters of 2020 were also sold during that year.
General and administrative expenses decreased by $125.7 million or 59%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to charges incurred in the prior year for professional fees incurred in relation to the Chapter 11 Cases prior to the Petition Date, professional fees associated with shareholder activism defense, organizational change initiatives, as well as merger integration related costs. This decline is partially offset by executive severance cost incurred in the Successor Period in connection with the separations of certain former members of executive management.
Other operating income decrease of $118.1 million was due to loss of hire insurance recoveries collected for the VALARIS DS-8 during the year ended December 31, 2020.
Other expense, net, includes reorganization expenses of $15.5 million, $3.6 billion and $527.6 million in the Successor Period, the 2021 Predecessor Period and the year ended December 31, 2020, respectively, for costs incurred as a direct result of the Chapter 11 Cases. Other expense, net, also includes interest expense of $31.0 million, $2.4 million and $291.9 million in the Successor Period, the 2021 Predecessor Period and the year ended December 31, 2020, respectively. The decrease in interest expense in the Successor Period results from our lower debt level following emergence from chapter 11. See “Note 2 - Chapter 11 Proceedings” for details related to reorganization items as well as changes in our debt and related interest.
Year Ended December 31, 2020 (Predecessor)
Revenues declined by $626.0 million, or 30%, as compared to the prior year. This decline is primarily attributable to a $287.4 million decline in revenue resulting from the sale of VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88, and VALARIS 96, which operated in the prior year comparative period, a $286.7 million decline in revenue as a result of fewer days under contract across our fleet, a $150.0 million decline in revenue due to the termination of the VALARIS DS-8 contract and a $28.3 million and $16.0 million decline in revenues earned under the Secondment Agreement and Transition Services Agreement with ARO, respectively. Further, the additional revenues earned under Lease Agreements with ARO due to the inclusion of a full year of results in 2020 as compared to the period from the date of the combination with Rowan in April 11, 2019 (the "Rowan Transaction") to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements. See "Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. The decline in revenue was partially offset by $113.6 million of revenue earned by rigs added from the Rowan Transaction, and $46.3 million of contract termination fees received for certain rigs.
Contract drilling expense declined by $337.4 million, or 19%, as compared to the prior year primarily due to a $184.4 million decline as a result of lower costs for idle rigs, $136.4 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5, VALARIS DS-6, VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 96, as these rigs were sold, and reduced costs resulting primarily from spend control efforts. Additionally, there was a decline in expenses due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020. This decrease was partially offset by $140.1 million of contract drilling expenses incurred on rigs added from the Rowan Transaction.
During the year ended December 31, 2020 (Predecessor), we recorded non-cash losses on impairment totaling $3.6 billion, with respect to assets in our fleet, primarily due to the adverse change in the current and anticipated market for these assets. See "Note 8 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Depreciation expense declined by $68.9 million, or 11%, as compared to the prior year primarily due to lower depreciation expense on certain assets which were impaired during the first and second quarters of 2020, some of which were subsequently sold in the third and fourth quarters of 2020. This decrease was partially offset by depreciation expense recorded for rigs added in the Rowan Transaction as well as for the VALARIS 123 which commenced operations in August 2019.
General and administrative expenses increased by $25.7 million, or 14%, as compared to the prior year primarily due to 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. This increase was partially offset by merger related costs incurred in the prior year comparative period.
Other operating income of $118.1 million recognized during 2020 was due to loss of hire insurance recoveries collected for the VALARIS DS-8 non-drilling incident.
Other expense, net, increased by $1.4 billion as compared to the prior year, primarily due to the prior period $637.0 million gain on bargain purchase recognized in connection with the Rowan Transaction, pre-tax gain related to the settlement award from the SHI matter of $200.0 million and $194.1 million of pre-tax gain on debt extinguishment related to the repurchase of senior notes in connection with July 2019 tender offers. Additionally, the current year period includes $527.6 million of reorganization items directly related to the Chapter 11 Cases. Partially offsetting these increases, our Interest Expense, net decreased $137.7 million primarily due to a $140.7 million reduction as we discontinued accruing interest on our outstanding debt subsequent to the chapter 11 filing.
Rig Counts, Utilization and Average Day Rates
The following table summarizes our offshore drilling rigs by reportable segment, rigs held-for-sale and ARO's offshore drilling rigs as of December 31, 2021 (Successor), 2020 (Predecessor) and 2019 (Predecessor):
2021 2020 2019
Floaters(1)
16 16 24
Jackups(2)
33 36 41
Other(3)
7 9 9
Held-for-sale(4)
- - 3
Total Valaris 56 61 77
ARO(5)
7 7 7
(1)During 2020, we sold VALARIS 5004, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6.
(2)During 2021, we sold VALARIS 100, VALARIS 101, VALARIS 142.
During 2020, we sold VALARIS 71, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 105.
(3)This represents the rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All jackup rigs leased to ARO are under three-year contracts with Saudi Aramco. During 2021, we sold VALARIS 37 and VALARIS 22, which were previously leased to ARO.
(4)During 2019, we classified VALARIS 68, VALARIS 70 and VALARIS 6002 as held-for-sale, all of which were subsequently sold in 2020.
(5)This represents the 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.
We are a party to contracts whereby we have the option to take delivery of two drillships, VALARIS DS-13 and VALARIS DS-14, 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. The first of these newbuild rigs is expected to be delivered in the fourth quarter of 2022 with the second rig expected either late in the fourth quarter of 2022 or in the first quarter of 2023.
The following table summarizes our and ARO's rig utilization and average day rates by reportable segment for each of the years in the three-year period ended December 31, 2021. Rig utilization and average day rates include results of rigs added in the Rowan Transaction or ARO from the date the Rowan Transaction closed in April 2019:
2021 2020 2019
Rig Utilization(1)
Floaters 27% 26% 47%
Jackups 54% 54% 66%
Other(2)
100% 98% 100%
Total Valaris 54% 52% 63%
ARO 87% 89% 93%
Average Day Rates(3)
Floaters $ 192,984 $ 192,057 $ 218,837
Jackups 95,304 86,266 78,133
Other(2)
31,301 37,580 49,236
Total Valaris $ 88,847 $ 87,547 $ 108,313
ARO $ 73,799 $ 82,624 $ 71,170
(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. Beginning in 2021, our method for calculating rig utilization has been updated to remove the impact of suspension periods. To the extent applicable, comparative period calculations have been retroactively adjusted.
For newly-constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a 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, demobilizations and shipyard contracts. Beginning in 2021, our method for calculating average day rates has been updated to remove the impact of suspension periods. To the extent applicable, comparative period calculations have been retroactively adjusted.
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 Rig Lease Agreements, the Secondment Agreement and the Transition Services Agreement. Floaters, Jackups and ARO are also reportable segments.
Upon emergence, we ceased allocation of our onshore support costs included within contract drilling expenses to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items”. We have adjusted the historical periods to conform with current period presentation. 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". Substantially all of the expenses incurred associated with our Transition Services Agreement with ARO are included in General and administrative under "Reconciling Items" in the table set forth below.
The full operating results included below for ARO (representing only results of ARO from the closing date of the Rowan Transaction) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO.
Upon establishment of ARO, Rowan entered into (1) an agreement to provide certain back-office services for a period of time until ARO develops its own infrastructure (the "Transition Services Agreement"), and (2) the Secondment Agreement. These agreements remained in place subsequent to the Rowan Transaction. Pursuant to these agreements, we or our seconded employees provide various services to ARO, and in return, ARO provides remuneration for those services. During the quarter ended June 30, 2020, almost all remaining employees seconded to ARO became employees of ARO. Further, our services to ARO under the Transition Services Agreement were completed as of December 31, 2020. See "Note 6 - 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.
Segment information for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively are presented below (in millions).
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 (172.3) 728.7
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 $ (129.4) $ (11.9)
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 losses 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 (246.0) 1,072.5
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 $ (224.6) $ (902.0)
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)
Year Ended December 31, 2019 (Predecessor)
Floaters Jackups ARO Other Reconciling Items Consolidated Total
Revenues $ 1,014.4 $ 834.6 $ 410.5 $ 204.2 $ (410.5) $ 2,053.2
Operating expenses
Contract drilling
(exclusive of depreciation) 785.0 711.3 280.2 111.0 (79.7) 1,807.8
Loss on impairment 88.2 10.2 - - 5.6 104.0
Depreciation 362.3 203.3 40.3 25.5 (21.7) 609.7
General and administrative - - 27.1 - 161.8 188.9
Equity in losses of ARO - - - - (12.6) (12.6)
Operating income (loss) $ (221.1) $ (90.2) $ 62.9 $ 67.7 $ (489.1) $ (669.8)
Floaters
2021 compared to 2020
Floater revenue declined $135.6 million, or 27%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $121.0 million resulting from fewer operating days in the current year and $46.3 million due to termination fees received for certain rigs in the prior year. This decline was partially offset by a $45.9 million increase in revenue from certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.
Floater contract drilling expense declined $208.9 million, or 37%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year. This decline is primarily due to $190.8 million as a result of lower costs for idle rigs in addition to lower costs of $31.4 million from rigs sold between the comparative periods. This decrease was partially offset by an increase of $35.1 million in reactivation cost for certain rigs stacked in the prior year.
During the 2021 Predecessor Period, we recorded a non-cash loss on impairment totaling $756.5 million with respect to certain assets in our Floater segment. During 2020, we recorded a non-cash loss on impairment of $3.4 billion, with respect to assets in our Floater segment due to the adverse change in the current and anticipated market for these assets. See "Note 8 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Floater depreciation expense declined $159.7 million, or 61%, for the combined Successor and Predecessor results for the year ended December 31, 2021, as compared to the prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to impairment of certain non-core assets in 2020 and the first quarter of 2021.
Other operating income of $118.1 million recognized by the Predecessor during 2020 was due to loss of hire insurance recoveries collected for the VALARIS DS-8 non-drilling incident.
2020 compared to 2019 (Predecessor)
During 2020, revenues declined by $508.6 million, or 50%, as compared to the prior year due to $241.0 million from the sale of VALARIS 5004, VALARIS 5006, and VALARIS 6002, which operated in the prior year comparative period, $189.4 million as a result of fewer days under contract across the floater fleet and $150.0 million due to the termination of the VALARIS DS-8 contract. This decline was partially offset by $46.3 million of contract termination fees received for certain rigs and $40.1 million earned by rigs added in the Rowan Transaction.
Contract drilling expense declined by $218.9 million, or 28%, as compared to the prior year primarily due to $131.1 million lower cost on idle rigs, $93.2 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6, as such rigs were sold, and reduced costs resulting primarily from spend control efforts. This decrease was partially offset by $53.8 million of contract drilling expense incurred by rigs added in the Rowan Transaction.
During 2020, we recorded a non-cash loss on impairment of $3.4 billion, with respect to assets in our Floater segment due to the adverse change in the current and anticipated market for these assets. See "Note 8 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Depreciation expense declined by $99.5 million, or 27%, compared to the prior year primarily due to lower depreciation on certain non-core assets which were impaired during the first and second quarters of 2020 and subsequently sold in the third and fourth quarters of 2020 with the exception of one floater.
Other operating income of $118.1 million recognized during 2020 was due to loss of hire insurance recoveries collected for the VALARIS DS-8 non-drilling incident.
Jackups
2021 compared to 2020
Jackup revenues declined $45.8 million, or 6%, for the combined Successor and Predecessor results for the year ended December 31, 2021, as compared to the prior year, primarily due to declines of $80.1 million resulting from fewer operating days in the current year. This decline was partially offset by a $71.4 million increase in revenue for certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.
Jackup contract drilling expense declined $119.3 million, or 18%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year. This decline was primarily due to $89.0 million of lower costs for idle rigs, $46.4 million from rigs sold between the comparative periods and $26.5 million in reduced costs for contract preparation projects in 2020. This decrease was partially offset by an increase of $49.3 million in reactivation costs for certain rigs stacked in the prior year.
Jackup depreciation expense declined $115.5 million, or 53%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to impairments of certain non-core assets in the first and second quarters of 2020.
2020 compared to 2019 (Predecessor)
During 2020, revenues declined by $69.3 million, or 8%, as compared to the prior year primarily due to $97.3 million as a result of fewer days under contract across the jackup fleet and $46.4 million due to the sale of VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88, and VALARIS 96, which operated in the prior year period. This decrease was partially offset by $73.5 million of revenue earned by rigs added in the Rowan Transaction.
Contract drilling expense declined by $51.8 million, or 7%, as compared to the prior year primarily due to $53.3 million lower cost on idle rigs, $43.2 million from the sale of VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 96 which operated in the prior year period, and reduced costs resulting from spend control efforts. This decrease was partially offset by $86.3 million of contract drilling expense incurred by rigs added in the Rowan Transaction.
During 2020, we recorded a non-cash loss on impairment of $254.3 million with respect to assets in our Jackup segment primarily due to the adverse change in the current and anticipated market for these assets. See "Note 8 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Depreciation expense increased by $13.9 million, or 7%, as compared to the prior year primarily due to the addition of rigs in our combination with Rowan in April 2019 as well as the commencement of operations of the VALARIS 123 in August 2019. This increase was partially offset by lower depreciation on certain non-core assets which were impaired during 2020 of which three of these jackups were sold in 2020.
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. The first rig is expected to be delivered in the fourth quarter of 2022, and the second rig is expected either late in the fourth quarter of 2022 or in the first quarter of 2023. ARO is expected to place orders for two additional newbuild jackups later this year. 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, on a proportionate basis.
The joint venture partners agreed that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. 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. We lease eight rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. Seven jackup rigs leased to ARO are operating under three-year contracts, or related extensions, with Saudi Aramco. We expect ARO to execute a long-term contract with Saudi Aramco for the remaining leased rig in the first quarter of 2022. All seven ARO-owned jackup rigs are operating under long-term contracts with Saudi Aramco. See "Note 6 - 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.
The results of ARO reflect the periods from the date of the Rowan Transaction in April 2019 through December 31, 2021.
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. Costs incurred under the Secondment Agreement are included in Contract drilling expense and general and administrative, depending on the function to which the seconded employees' services related. General and administrative expenses include costs incurred under the Transition Services Agreement and other administrative costs. Services under the Transition Services Agreement were completed as of December 31, 2020.
2021 compared to 2020
Revenue for 2021 decreased $78.8 million or 14% as compared to the prior year primarily due to $56.0 million from lower day rates, as well as, $8.7 million decrease from fewer operating days related to certain rigs for which operations were temporarily suspended or which were undergoing maintenance. Additionally, a decrease of $9.3 million related to one rig leased to ARO which completed its contract in August 2021.
Contract drilling expense for 2021 decreased $25.9 million or 7% as compared to the prior year primarily due to $17.7 million lower costs for repairs and maintenance and an $8.1 million reduction in expenses related to lower support costs as compared to the prior year.
Depreciation expense for 2021 increased $10.4 million or 19% as compared to the prior year primarily due to capital expenditures.
General and administrative expenses for 2021 decreased $6.4 million or 26% as compared to the prior year, primarily due to a reduction in labor cost, professional fees and services received under the Transition Services Agreement which was completed as of December 31, 2020.
2020 compared to 2019
During 2020, revenues increased by $138.9 million, or 34%, as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.
Contract drilling expense increased by $108.0 million, or 39%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.
Depreciation expense increased by $14.5 million, or 36%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.
General and administrative expenses decreased by $2.9 million, or 11%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a decrease in services received under the Transition Services Agreement.
See "Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO.
Other
2021 compared to 2020
Other revenues declined $13.4 million, or 9%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to $19.0 million of lower revenues earned under the Secondment Agreement, partially offset by a $4.9 million increase in revenue from the Lease Agreements with ARO. See "Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Other contract drilling expenses declined $24.0 million, or 29%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to a $19.0 million decrease in cost for services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.
Depreciation expense declined $27.2 million, or 61%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to the reduction in the values of property and equipment from the application of fresh start accounting.
2020 compared to 2019 (Predecessor)
Other revenues declined $48.1 million, or 24%, for the year ended December 31, 2020, as compared to the prior year, primarily due to lower revenues earned under the Secondment Agreement and Transition Services Agreement with ARO of $28.3 million and $16.0 million, respectively. Further, the additional revenues earned under Lease Agreements due to the inclusion of a full year of results in 2020 as compared to the period from April 11, 2019 to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements. See "Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Other contract drilling expenses declined $28.2 million, or 25%, for the year ended December 31, 2020, as compared to the prior year, primarily due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.
During 2020, we recorded a non-cash loss on impairment of $5.7 million, with respect to a certain contract intangible due to current market conditions. See "Note 5 - Rowan Transaction" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Depreciation expense increased $19.3 million, or 76%, as compared to the prior year primarily due to the impact of full year results for 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 as well as additional depreciation due to capital expenditures and the commencement of the VALARIS 147 and VALARIS 148 which were in the shipyard most of the comparative period.
Impairment of Long-Lived Assets
See "Note 8 - Property and Equipment" and "Note 16 - Leases" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on impairment of long-lived assets.
Other Income (Expense), Net
The following table summarizes other income (expense), net, (in millions):
Successor Predecessor Combined (Non-GAAP) Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Interest income $ 28.5 $ 3.6 $ 32.1 $ 19.7 $ 28.1
Interest expense, net:
Interest expense (31.0) (2.4) (33.4) (291.9) (449.2)
Capitalized interest - - - 1.3 20.9
(31.0) (2.4) (33.4) (290.6) (428.3)
Reorganization items, net (15.5) (3,584.6) (3,600.1) (527.6) -
Other, net 38.1 25.9 64.0 16.0 1,006.2
$ 20.1 $ (3,557.5) $ (3,537.4) $ (782.5) $ 606.0
Interest income increased by $12.4 million or 63% for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $20.8 million in amortization of the discount on our note receivable from ARO recorded in fresh start accounting. This increase was partially offset by a $5.8 million decrease due to lower LIBOR rates earned on our note receivable from ARO. Interest income decreased during 2020 (Predecessor) as compared to 2019 (Predecessor) primarily due to fewer investments.
Interest expense decreased by $258.5 million, or 89%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to a $258.7 million decrease in interest cost as a result of our lower debt level following emergence from chapter 11.
Interest expense decreased during 2020 by $157.3 million, or 35%, as compared to the prior year as we did not accrue interest of $140.7 million on our outstanding debt or amortize discounts, premiums and debt issuance costs of $29.8 million subsequent to the chapter 11 filing. Further, debt repurchases resulted in interest savings of $19.2 million. These declines were partially offset by increased interest on debt acquired from Rowan totaling $35.7 million.
Interest expense capitalized in the year ended December 31, 2019, was attributable to capital invested in newbuild construction. Following the delivery of our last newly constructed rig in 2019, capitalized interest declined significantly.
Reorganization items, net of $3.6 billion recognized for the 2021 Predecessor Period, was related to the effects of the emergence from bankruptcy including the application of fresh start accounting, legal and other professional advisory service fees pertaining to the Chapter 11 Cases and contract items related to rejecting certain operating leases.
Reorganization items, net of $527.6 million recognized during 2020 was related to other net losses and expenses directly related to the Chapter 11 Cases, consisting of the write off of unamortized debt discounts, premiums and issuance costs of $447.9 million, professional fees of $66.8 million and DIP facility fees costs of $20.0 million, partially offset by $7.1 million of contract items relating to rejection and amendment of certain operating leases. See "Note 2 - Chapter 11 Proceedings" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Other, net, increased by $48.0 million for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $32.5 million of net foreign currency exchange gains and losses, as discussed further below, and $15.4 million increase on gain from sale of certain assets.
Other, net, decreased by $990 million during the year ended December 31, 2020 (Predecessor) as compared to the prior year.
Other, net in 2020 (Predecessor) included $14.6 million of net periodic income, excluding service cost, for our pension and retiree medical plans, $11.8 million gain from sale of certain assets, a $3.2 million of net unrealized gains from marketable securities held in our supplemental executive retirement plans ("the SERP") and a $3.1 million pre-tax gain on extinguishment of debt. We also incurred $11.0 million of losses on net foreign currency exchange, as discussed further below, and had a $6.3 million reduction to gain on bargain purchase as a result of measurement adjustments made in the first quarter 2020 related to the Rowan Transaction.
Other, net in 2019 (Predecessor) included a gain on bargain purchase recognized in connection with the Rowan Transaction of $637.0 million, a pre-tax gain related to the settlement with Samsung Heavy Industries of $200.0 million, a pre-tax gain from debt extinguishment of $194.1 million related to the senior notes repurchased in connection with the July 2019 tender offers, and net unrealized gains of $5.0 million from marketable securities held in our SERP. During the same period, we also recognized a pre-tax loss of $20.3 million related to settlement of a dispute with a local partner of legacy Ensco plc in the Middle East, and a net foreign currency exchange loss of $7.4 million, as further discussed below.
Our functional currency is the U.S. dollar, 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 gain of $21.5 million, and losses (inclusive of offsetting fair value derivatives) of $11.0 million and $7.4 million, were included in Other, net, in our Consolidated Statements of Operations for the combined Successor and Predecessor results for the year ended December 31, 2021, 2020 (Predecessor) and 2019 (Predecessor), respectively.
Net foreign currency exchange gains for the combined Successor and Predecessor results for the year ended December 31, 2021 primarily included $11.7 million and $8.8 million related to Libyan dinar and euros, respectively. Net foreign currency exchange losses incurred during 2020 primarily included $7.3 million and $1.4 million related to euros and Angolan kwanza, respectively. Net foreign currency exchange losses incurred during 2019 included $3.3 million and $2.8 million, related to euros and Angolan kwanza, respectively.
Provision for Income Taxes
Valaris Limited, the Successor Company and our parent company, 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. Valaris plc, the Predecessor Company and our former parent company, 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.
U.S. Tax Reform and CARES Act
The U.S. Tax Cuts and Jobs Act (“U.S. tax reform”) was enacted on December 22, 2017 and introduced significant changes to U.S. income tax law, effective January 1, 2018. Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, the U.S. Treasury Department continued finalizing rules associated with U.S. tax reform during 2018 and 2019. During 2019, we recognized a tax expense of $13.8 million associated with final rules issued related to U.S. tax reform.
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 2018, 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.
Effective Tax Rate
During the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), we recorded an income tax expense of $37.4 million and $16.2 million, respectively. During the year ended December 31, 2020, we recorded an income tax benefit of $259.4 million and during the year ended December 31, 2019, we recorded an income tax expense of $128.4 million, respectively. Our consolidated effective income tax rates during the same periods were 456.1%, (0.4)%, 5.1% and (201.3)%, respectively.
Our eight months ended December 31, 2021 (Successor) consolidated effective income tax rate includes $15.3 million associated with the impact of various discrete items, including $30.7 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 included 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.
Our 2019 consolidated effective income tax rate included $2.3 million associated with the impact of various discrete tax items, including $28.3 million of tax expense associated with final rules relating to U.S. tax reform, gains on repurchase of debt and settlement proceeds, partially offset by $26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales.
Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) were 387.7% and (12.9)%, respectively. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020 and 2019 (Predecessor) were (7.6)% and (14.6)%, 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.
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 16 jackup rigs, five dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and three drillships during the three-year period ended December 31, 2021.
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.
We sold the following rigs during the eight months ended December 31, 2021 (Successor) and the period January 1, 2019 to April 30, 2021 (Predecessor) (in millions):
Rig Date of Sale Segment(1)
Net Proceeds Net Book Value(2)
Pre-tax Gain/(Loss)
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
Predecessor
VALARIS 101 April 2021 Jackups $ 26.4 $ 21.1 $ 5.3
VALARIS 8504 October 2020 Floater 4.7 4.0 0.7
VALARIS 88 October 2020 Jackups 1.4 0.3 1.1
VALARIS 84 October 2020 Jackups 1.2 0.3 0.9
VALARIS 105 September 2020 Jackups 2.1 0.8 1.3
VALARIS DS-6 August 2020 Floaters 5.7 6.1 (0.4)
VALARIS 87 August 2020 Jackups 0.3 0.2 0.1
VALARIS 8500 July 2020 Floaters 4.0 0.7 3.3
VALARIS 8501 July 2020 Floaters 4.0 0.7 3.3
VALARIS 8502 July 2020 Floaters 1.8 0.7 1.1
VALARIS DS-3 July 2020 Floaters 6.1 6.1 -
VALARIS DS-5 July 2020 Floaters 6.1 6.1 -
VALARIS 71 June 2020 Jackups 0.2 0.8 (0.6)
VALARIS 70 June 2020 Jackups 0.6 1.0 (0.4)
VALARIS 5004 April 2020 Floaters 1.9 2.0 (0.1)
VALARIS 68 January 2020 Jackups 0.3 0.3 -
VALARIS 6002 January 2020 Floaters 2.1 0.9 1.2
VALARIS 96 December 2019 Jackups 1.9 0.3 1.6
VALARIS 5006 November 2019 Floaters 7.0 6.0 1.0
VALARIS 42 October 2019 Jackups 2.9 2.5 0.4
Gorilla IV May 2019 Jackups 2.5 2.5 -
ENSCO 97 April 2019 Jackups 1.7 1.0 0.7
$ 84.9 $ 64.4 $ 20.5
(1) Classification denotes the location of the operating results and gain (loss) on sale for each rig in our Consolidated Statements of Operations.
(2) Includes the rig's net book value as well as materials and supplies and other assets on the date of the sale.
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. 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 and, if necessary, 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.
Our liquidity position is summarized in the table below (in millions, except ratios):
Successor Predecessor
December 31, 2021 December 31, 2020 December 31, 2019
Cash and cash equivalents $ 608.7 $ 325.8 $ 97.2
Available DIP facility capacity(1)
- 500.0 -
Available credit facility borrowing capacity - - 1,622.2
Total liquidity $ 608.7 $ 825.8 $ 1,719.4
Working capital $ 784.6 $ 746.1 $ 233.7
Current ratio 2.9 2.7 1.3
(1)On September 25, 2020, we entered into a $500.0 million DIP facility to provide liquidity when the Chapter 11 Cases were pending. However, the same was terminated upon our emergence from the Chapter 11 Cases on the Effective Date.
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 or business combinations, our primary sources and uses of cash are driven by cash generated from or used in operations and capital expenditures. Our net cash used in operating activities and capital expenditures were as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Net cash used in operating activities $ (26.2) $ (39.8) $ (251.7) $ (276.9)
Capital expenditures $ (50.2) $ (8.7) $ (93.8) $ (227.0)
During the eight months ended December 31, 2021 (Successor), our primary source of cash was proceeds of $25.1 million from the disposition of assets. Our primary uses of cash for the same period were $26.2 million used in operating activities and $50.2 million for the enhancement and other improvements of our drilling rigs. 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 from the disposition of assets. Our primary uses of cash for the same period were $39.8 million used in operating activities and $8.7 million for the enhancement and other improvements of our drilling rigs.
Net cash used in operating activities during the eight months ended December 31, 2021 (Successor) primarily relates to reorganization costs and interest payments on the First Lien Notes while net cash used in operating activities for the four months ended April 30, 2021 (Predecessor) primarily relates to reorganization costs, partially offset by cash received from a tax refund.
During the year ended December 31, 2020 (Predecessor), our primary sources of cash were $596 million from borrowings on our credit facility and proceeds of $51.8 million for the disposition of assets. Our primary uses of cash for the same period were $251.7 million used in operating activities and $93.8 million for the enhancement and other improvements of our drilling rigs.
During 2020 (Predecessor), cash flows used in operating activities decreased by $25.2 million as compared to the prior year due to lower interest costs, partially offset by declining margins.
During the year ended December 31, 2019 (Predecessor), our primary sources of cash were cash acquired of $931.9 million in the Rowan acquisition and proceeds of $474.0 million from the maturity of short-term investments. Our primary uses of cash for the same period were $928.1 million used to repay long-term borrowings, $276.9 million used in operating activities and $227.0 million for the enhancement and other improvements of our drilling rigs.
Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14. On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy. The amendments 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 rigs on or before December 31, 2023. Under the amended agreements, the purchase price for the rigs is estimated to be approximately $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. The amended agreements removed any parent company guarantee.
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 this reactivation cost will be operating expenses, recognized in the income statement, related to de-preservation activities, including reinstalling key pieces of equipment and crewing up the rigs. Capital expenditures during reactivations include rig modifications, equipment overhauls and any customer required capital upgrades. We would generally expect to be compensated for these customer-specific enhancements.
Based on our current projections, we expect capital expenditures during 2022 to approximate $225 million to $250 million for rig enhancement, reactivation and upgrade projects. We expect that customers will reimburse us for a significant portion of the 2022 expenditures. Depending on market conditions and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.
Approximately $70 million of our expected capital expenditures for 2022 relate to the reactivation and upgrade of the VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S. Gulf of Mexico expected to commence in mid-2024. The contract requires the rig to be upgraded with 20,000 psi well-control equipment. In February 2022, the customer decided not to sanction and therefore withdraw from the project associated with this contract. As of the date hereof, the customer has not terminated the contract, but may do so upon the payment of an early termination fee should the project not receive a final investment decision (FID). The project has not received FID. We are in discussions with the customer and its partner on the project to determine next steps. In the event of termination, the early termination fee and contractual reimbursements from the customer will be more than sufficient to cover expenses and commitments incurred by Valaris on the project.
As we begin to reactivate rigs, we expect future spending levels to increase beyond the levels we incurred in 2020 and 2021, with more spending associated with reactivation of our floater fleet relative to our jackup fleet and for rigs that have been preservation stacked for longer periods of time.
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.
Financing and Capital Resources
Successor First Lien Notes
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 shares in an aggregate principal amount of $550 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 million in cash in exchange for a $550 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: (i) 8.25% per annum, payable in cash; (ii) 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 (iii) 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. The first cash interest payment was made on November 1, 2021.
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% 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 (expressed as percentages of the principal amount), plus accrued and unpaid interest, if any, to, but excluding, the redemption date. The Company may also redeem the First Lien Notes, in whole or in part, at any time and from time to time on or after April 30, 2026 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if any, to, but excluding, the applicable 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: (i) incur, assume or guarantee additional indebtedness; (ii) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (iii) make investments; (iv) repay or redeem junior debt; (v) transfer or sell assets; (vi) enter into sale and lease back transactions; (vii) create, incur or assume liens; and (viii) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions. As of December 31, 2021, we were in compliance with our covenants under the Indenture.
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.
Predecessor Senior Notes
The commencement of the Chapter 11 Cases was considered an event of default under each series of 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 Predecessor 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 Sheet as of December 31, 2020. On the Effective Date, pursuant to the plan of reorganization, each series of our senior notes were cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization.
See "Note 2 - Chapter 11 Proceedings" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information related to our emergence from Chapter 11 Cases and cancellation of Predecessor debt.
Tender Offers and Open Market Repurchases (Predecessor)
In early March 2020, we repurchased $12.8 million of our outstanding 4.70% 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.
On June 25, 2019, we commenced cash tender offers for certain series of senior notes issued by us and certain of our wholly-owned subsidiaries. The tender offers expired on July 23, 2019, and we repurchased $951.8 million of our outstanding senior notes for an aggregate purchase price of $724.1 million. As a result of the transaction, we recognized a pre-tax gain from debt extinguishment of $194.1 million, net of discounts, premiums and debt issuance costs.
Predecessor Revolving Credit Facility
The commencement of the Chapter 11 Cases constituted an event of default under our then existing 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 borrowings 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. 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.
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 long-term notes receivable and from the distribution of earnings from ARO. The long-term notes receivable, which are governed by the laws of Saudi Arabia, mature during 2027 and 2028. In the event that ARO is unable to repay these notes when they become due, we would require the prior consent of our joint venture partner to enforce ARO’s payment obligations.
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 6 - 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, 2021 (in millions):
Maturity Date Principal amount
October 2027 $ 265.0
October 2028 177.7
Total $ 442.7
Contractual Obligations
The following table summarizes our significant contractual obligations as of December 31, 2021 and the periods in which such obligations are due (in millions):
Payments due by period
2022 2023 and 2024 2025 and 2026 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 68.1 294.9
Operating leases 11.3 5.3 4.0 6.8 27.4
Total contractual obligations(2)
$ 56.7 $ 96.0 $ 94.7 $ 624.9 $ 872.3
(1)Interest on the First Lien Notes accrues, at our option, at a rate of: (i) 8.25% per annum, payable in cash; (ii) 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 (iii) 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 $320.2 million of unrecognized tax benefits, inclusive of interest and penalties, included on our Consolidated Balance Sheet as of December 31, 2021. 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 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, with the first rig expected to be delivered in the fourth quarter of 2022 and the second rig is expected either late in the fourth quarter or in the first quarter of 2023. ARO is expected to place orders for two additional newbuild jackups in 2022. 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, on a proportionate basis. See "Note 6 - 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.
Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14. On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy. The amendments 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 rigs on or before December 31, 2023. Under the amended agreements, the purchase price for the rigs are estimated to be approximately $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. The amended agreements removed any parent company guarantee.
Other Commitments
We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of December 31, 2021, we were contingently liable for an aggregate amount of $36.5 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, 2021, we had collateral deposits in the amount of $31.1 million with respect to these agreements.
The following table summarizes our other commitments as of December 31, 2021 (in millions):
Commitment expiration by period
2022 2023 and 2024 2025 and 2026 Thereafter Total
Letters of credit $ 23.8 $ 12.7 $ - $ - $ 36.5
Tax Assessments
During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $73.4 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 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have an $18 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2021. 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 14 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the tax assessments.
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, (i) first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by Valaris Limited or any Guarantor and (ii) 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.
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 (i) that is not secured by a lien on the Collateral securing the First Lien Notes, or (ii) 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 (i) that is secured by a lien on the Collateral that is senior or prior to the lien securing the First Lien Notes, or (ii) 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 combined value of the affiliates whose securities are pledged as Collateral constitutes substantially all of the Company’s value, including assets, liabilities and results of operations. As such, 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 the consolidated financial statements of the Company. 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.
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:
Successor Predecessor
(in millions) December 31,
2021 December 31, 2020
ASSETS
Current assets $ 1,140.2 $ 901.8
Amounts due from non-guarantor subsidiaries, current 785.8 756.5
Amounts due from related party, current 13.1 20.5
Noncurrent assets 989.8 10,514.5
Amounts due from non-guarantor subsidiaries, noncurrent 1,469.7 4,879.2
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities 308.0 369.4
Amounts due to non-guarantor subsidiaries, current 55.3 865.5
Amounts due to related party, current 38.3 -
Long-term debt 545.3 -
Noncurrent liabilities 438.5 653.4
Amounts due to non-guarantor subsidiaries, noncurrent 1,921.6 7,848.6
Noncontrolling interest 2.6 (4.4)
Summarized Statement of Operations Information:
Successor Predecessor
(in millions) Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Operating revenues $ 843.9 $ 384.1 $ 1,583.1 $ 2,344.6
Operating revenues from related party 37.0 23.1 63.0 79.3
Operating costs and expenses 847.5 1,268.2 5,790.1 2,672.2
Reorganization expense (15.6) (3,584.1) 12.9 -
Income (loss) from continuing operations before income taxes 174.3 (4,337.0) (3,688.7) (511.4)
Net income (loss) attributable to noncontrolling interest (3.8) (3.2) 2.1 (5.8)
Net income (loss) 170.5 (4,340.2) (3,686.6) (517.2)
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. At the December 2015 Conference of the Parties to the United Nations Framework Convention on Climate Change held in Paris, an agreement was reached that requires countries to review and “represent a progression” in their intended nationally determined contributions to the reduction of GHG emissions, setting GHG emission reduction goals every five years beginning in 2020. This agreement, known as the Paris Agreement, entered into force on November 4, 2016. The United Nations Climate Change Conference held in Katowice, Poland in December 2018 adopted further rules regarding the implementation of the Paris Agreement and, in connection with this conference, numerous countries issued commitments to increase their GHG emission reduction targets. Although the United States had withdrawn from the Paris Agreement in November 2020, the current Presidential Administration officially reentered the United States into the agreement in February 2021. 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 and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad. The latter executive order 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. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation challenging that aspect of the executive order is ongoing. On January 27, 2022, the United States District Court for the District of Columbia found that the Bureau of Ocean Energy Management’s failure to calculate the potential emissions from foreign oil consumption violated the agency’s approval of oil and gas leases in the Gulf of Mexico under the National Environmental Policy Act. 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.
During 2009, the United States Environmental Protection Agency (the “EPA”) officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish permitting requirements, including emissions control technology requirements, for certain large stationary sources that are potential major sources of GHG emissions. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain onshore and offshore oil and natural gas production facilities. Although a number of bills related to climate change have been introduced in the U.S. Congress in the past, comprehensive federal climate legislation has not yet been passed by Congress. If such legislation were to be adopted in the U.S., such legislation could adversely impact many industries. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs and commitments to contribute to meeting the goals of the Paris Agreement.
Future 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.
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" 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, impairment of 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, 2021, the carrying value of our property and equipment totaled $890.9 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.
Prior to emergence from bankruptcy, we recorded our drilling rigs as a single asset with a useful life ascribed by the expected useful life of that asset. Upon emergence, we identified the significant components of our drilling rigs and ascribed useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.
The judgments and assumptions used in determining the next overhaul or the economic lives of the components of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of the significant components our rigs, would likely result in materially different asset carrying values and operating results.
The useful lives of our drilling rigs 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 rigs 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 45% of the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2021. Our fleet of 33 jackup rigs represented 44% of the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2021.
Impairment of Property and Equipment
We do not consider Impairment of Property and Equipment to be a critical accounting policy for Valaris Limited (Successor) due to the significantly reduced carrying values. However, for Legacy Valaris (Predecessor), this was a critical accounting policy and have included disclosure below for historical periods.
During the four months ended April 30, 2021, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters of $756.5 million. During the year ended December 31, 2020 and the year ended December 31, 2019, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters, jackups and spare equipment of $3.6 billion and $98.4 million, respectively. See "Note 8 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our impairments of property and equipment.
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. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.
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 between the carrying value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization levels, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.
Our judgments and assumptions about future cash flows to be generated by our drilling rigs are highly subjective and based on consideration of the following:
•global macroeconomic and political environment,
•historical utilization, day rate and operating expense trends by asset class,
•regulatory requirements such as surveys, inspections and recertification of our rigs,
•remaining useful lives of our rigs,
•expectations on the use and eventual disposition of our rigs,
•weighted-average cost of capital,
•oil price projections,
•sanctioned and unsanctioned offshore project data,
•offshore economic project break-even data,
•global rig supply and construction orders,
•global rig fleet capabilities and relative rankings, and
•expectations of global rig fleet attrition.
We collect and analyze the above information to develop a range of estimated utilization levels, day rates, expense levels and capital requirements, as well as estimated cash flows generated upon disposition. The drivers of these assumptions that impact our impairment analyses include projections of future oil prices and timing of global rig fleet attrition, which, in large part, impact our estimates on timing and magnitude of recovery from the current industry downturn. However, there are numerous judgments and assumptions unique to the projected future cash flows of each rig that individually, and in the aggregate, can significantly impact the recoverability of its carrying value.
The highly cyclical nature of our industry cannot be reasonably predicted with a high level of accuracy and, therefore, differences between our historical judgments and assumptions and actual results will occur. We reassess our judgments and assumptions in the period in which significant differences are observed and may conclude that a triggering event has occurred and perform a recoverability test. We recognized impairment charges in recent periods upon observation of significant unexpected changes in our business climate and estimated useful lives of certain assets.
There are numerous factors underlying the highly cyclical nature of our industry that are reasonably likely to impact our judgments and assumptions including, but not limited to, the following:
•changes in global economic conditions and demand,
•production levels of the Organization of Petroleum Exporting Countries (“OPEC”),
•production levels of non-OPEC countries,
•advances in exploration and development technology,
•offshore and onshore project break-even economics,
•development and exploitation of alternative fuels,
•natural disasters or other operational hazards,
•changes in relevant law and governmental regulations,
•political instability and/or escalation of military actions in the areas we operate,
•changes in the timing and rate of global newbuild rig construction, and
•changes in the timing and rate of global rig fleet attrition.
There is a wide range of interrelated changes in our judgments and assumptions that could reasonably occur as a result of unexpected developments in the aforementioned factors, which could result in materially different carrying values for an individual rig, group of rigs or our entire rig fleet, materially impacting our operating results.
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, 2021, our Consolidated Balance Sheet included an $47.3 million net deferred income tax asset, a $31.0 million liability for income taxes currently payable and a $320.2 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.
Tax returns are routinely subject to audit in most jurisdictions and tax liabilities occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:
•During recent years, the number of tax jurisdictions in which we conduct operations has increased.
•In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed and challenged by tax authorities.
•We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.
•Tax laws, regulations, agreements, treaties and the administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.
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, 2021, included (1) a weighted average discount rate of 2.73% to determine pension benefit obligations, (2) a weighted average discount rate of 2.84% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.03% to determine net periodic pension cost. 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. 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, 2021, a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $109.1 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 $4.1 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 6.26% at December 31, 2021 from 6.03% at December 31, 2020. See "Note 13 - 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Not applicable.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 Interim 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, 2021 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 22, 2022
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, 2021 (Successor) and 2020 (Predecessor), the related consolidated statements of operations, comprehensive loss, and cash flows for the periods from May 1, 2021 to December 31, 2021 (Successor period) and from January 1, 2021 to April 30, 2021 and for each of the years in the two-year period 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, 2021 (Successor) and 2020(Predecessor), and the results of its operations and its cash flows for the 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, 2021, 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 22, 2022 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, 2021 and for the Successor period 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 with prior periods.
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.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 critical audit matters 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 separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Valuation of drilling rigs upon emergence from bankruptcy
As disclosed in Note 3 to the consolidated financial statements, on April 30, 2021, the Company satisfied all conditions to effect its Plan of Reorganization and emerged from Chapter 11 bankruptcy. In connection with its emergence and in accordance with ASC 852, the Company qualified for and applied fresh start accounting. The Company involved third-party valuation advisors to assist with the valuation process of certain assets valued in fresh start. The Company's principal assets are its property and equipment, which is primarily comprised of the drilling rigs. As part of fresh start accounting, management recorded property, plant and equipment of $909.1 million, a portion of which related to the drilling rigs. The valuation of the Company's drilling rigs was estimated using an income approach or estimated sales price.
We identified the valuation of the Company's drilling rigs upon emergence from bankruptcy as a critical audit matter. A higher degree of subjective auditor judgment was required to evaluate the methodology used in the application of the adjustment to reconcile the fair value of the drilling rigs to the reorganization value and certain assumptions used in the Company's determination of fair value of its drilling rigs using the income approach. Specifically, future day rates and utilization associated with rig stacking assumptions were based on unobservable inputs for which there was limited information. In addition, the audit effort involved the use of professionals with specialized skills and knowledge.
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 related to the emergence date valuation process. This included controls related to management's valuation methodology and the application of fresh start accounting, including application of the adjustment to reconcile the fair value of the drilling rigs to the reorganization value, and controls related to the development of the future day rates and utilization associated with rig stacking assumptions used in the valuation of the drilling rigs. We evaluated the reasonableness of the future day rates used in the income approach by comparing them to contractual agreements with consideration of the current industry environment and economic trends, including third-party forecasted oil prices and demand curves. We evaluated the reasonableness of the utilization associated with rig stacking assumptions by comparing the timing of scheduled rig reactivations to third-party demand and supply forecasts. We involved valuation professionals with specialized skills and knowledge who assisted in evaluating the accuracy of management's model in applying the methodology used in the application of the adjustment to reconcile the valuation of the drilling rigs to the reorganization value. We also involved professionals with specialized skills and knowledge who assisted in evaluating the appropriateness of the methodology used in the application of the adjustment to reconcile the valuation of the drilling rigs to the reorganization value.
Income tax positions pertaining to certain tax transactions
As discussed in Note 1 and 14 to the consolidated financial statements, the Company evaluates 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 in 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 22, 2022
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, 2021, 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, 2021, 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, 2021 (Successor) and 2020 (Predecessor), the related consolidated statements of operations, comprehensive loss, and cash flows for the periods from May 1, 2021 to December 31, 2021 (Successor period) and from January 1, 2021 to April 30, 2021 and for each of the years in the two-year period ended December 31, 2020 (Predecessor periods), and the related notes (collectively, the consolidated financial statements), and our report dated February 22, 2022 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.
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 22, 2022
VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
OPERATING REVENUES $ 835.0 $ 397.4 $ 1,427.2 $ 2,053.2
OPERATING EXPENSES
Contract drilling (exclusive of depreciation) 728.7 343.8 1,470.4 1,807.8
Loss on impairment - 756.5 3,646.2 104.0
Depreciation 66.1 159.6 540.8 609.7
General and administrative 58.2 30.7 214.6 188.9
Total operating expenses 853.0 1,290.6 5,872.0 2,710.4
OTHER OPERATING INCOME - - 118.1 -
EQUITY IN EARNINGS (LOSSES) OF ARO 6.1 3.1 (7.8) (12.6)
OPERATING LOSS (11.9) (890.1) (4,334.5) (669.8)
OTHER INCOME (EXPENSE)
Interest income 28.5 3.6 19.7 28.1
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)
(31.0) (2.4) (290.6) (428.3)
Reorganization items, net (15.5) (3,584.6) (527.6) -
Other, net 38.1 25.9 16.0 1,006.2
20.1 (3,557.5) (782.5) 606.0
INCOME (LOSS) BEFORE INCOME TAXES 8.2 (4,447.6) (5,117.0) (63.8)
PROVISION (BENEFIT) FOR INCOME TAXES
Current income tax expense (benefit) 58.7 34.4 (153.7) 104.5
Deferred income tax expense (benefit) (21.3) (18.2) (105.7) 23.9
37.4 16.2 (259.4) 128.4
NET LOSS (29.2) (4,463.8) (4,857.6) (192.2)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS (3.8) (3.2) 2.1 (5.8)
NET LOSS ATTRIBUTABLE TO VALARIS $ (33.0) $ (4,467.0) $ (4,855.5) $ (198.0)
LOSS PER SHARE - BASIC AND DILUTED $ (0.44) $ (22.38) $ (24.42) $ (1.14)
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic and Diluted 75.0 199.6 198.9 173.4
The accompanying notes are an integral part of these consolidated financial statements.
VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in millions)
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
NET LOSS $ (29.2) $ (4,463.8) $ (4,857.6) $ (192.2)
OTHER COMPREHENSIVE LOSS, NET
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive loss, net of income tax benefit of $5.9 million for the year ended December 31, 2019. No income tax benefit was recognized during the eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor), and year ended December 31, 2020 (Predecessor).
(9.1) 0.1 (76.3) (21.7)
Net change in fair value of derivatives - - (5.4) 1.6
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) losses on derivative instruments from other comprehensive loss into net loss - (5.6) (11.6) 8.3
Other - - (0.6) (0.2)
NET OTHER COMPREHENSIVE LOSS (9.1) (5.5) (94.1) (12.0)
COMPREHENSIVE LOSS (38.3) (4,469.3) (4,951.7) (204.2)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS (3.8) (3.2) 2.1 (5.8)
COMPREHENSIVE LOSS ATTRIBUTABLE TO VALARIS $ (42.1) $ (4,472.5) $ (4,949.6) $ (210.0)
The accompanying notes are an integral part of these consolidated financial statements.
VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share and par value amounts)
Successor Predecessor
December 31, 2021 December 31, 2020
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 608.7 $ 325.8
Restricted cash 35.9 11.4
Accounts receivable, net 444.2 449.2
Other current assets 117.8 386.5
Total current assets 1,206.6 1,172.9
PROPERTY AND EQUIPMENT, AT COST 957.0 13,209.3
Less accumulated depreciation 66.1 2,248.8
Property and equipment, net 890.9 10,960.5
LONG-TERM NOTES RECEIVABLE FROM ARO 249.1 442.7
INVESTMENT IN ARO 86.6 120.9
OTHER ASSETS 176.0 176.2
$ 2,609.2 $ 12,873.2
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade $ 225.8 $ 176.4
Accrued liabilities and other 196.2 250.4
Total current liabilities 422.0 426.8
LONG-TERM DEBT 545.3 -
OTHER LIABILITIES 581.1 762.4
Total liabilities not subject to compromise 1,548.4 1,189.2
LIABILITIES SUBJECT TO COMPROMISE - 7,313.7
COMMITMENTS AND CONTINGENCIES
VALARIS SHAREHOLDERS' EQUITY
Predecessor Class A ordinary shares, U.S. $0.40 par value, 206.1 million shares issued as of December 31, 2020
- 82.5
Predecessor Class B ordinary shares, £1 par value, 50,000 shares issued as of December 31, 2020
- 0.1
Successor common shares, $0.01 par value, 700 million shares authorized, 75 million shares issued as of December 31, 2021
0.8 -
Successor preference shares, $0.01 par value, 150 million shares authorized, no shares issued as of December 31, 2021
- -
Successor stock warrants 16.4 -
Additional paid-in capital 1,083.0 8,639.9
Retained deficit (33.0) (4,183.8)
Accumulated other comprehensive loss (9.1) (87.9)
Predecessor Treasury shares, at cost, 6.6 million shares as of December 31, 2020
- (76.2)
Total Valaris shareholders' equity 1,058.1 4,374.6
NONCONTROLLING INTERESTS 2.7 (4.3)
Total equity 1,060.8 4,370.3
$ 2,609.2 $ 12,873.2
The accompanying notes are an integral part of these consolidated financial statements.
VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
OPERATING ACTIVITIES
Net loss $ (29.2) $ (4,463.8) $ (4,857.6) $ (192.2)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation expense 66.1 159.6 540.8 609.7
Deferred income tax expense (benefit) (21.3) (18.2) (105.7) 23.9
Gain on asset disposals (21.2) (6.0) (11.8) (1.8)
Accretion of discount on shareholders note (20.8) - - -
Net periodic pension and retiree medical income (8.7) (5.4) (14.6) (4.3)
Equity in losses (earnings) of ARO (6.1) (3.1) 7.8 12.6
Share-based compensation expense 4.3 4.8 21.4 37.3
Amortization, net 2.3 (4.8) 6.2 (16.8)
Debt discounts and other 0.5 - 36.8 31.5
Loss on Impairment - 756.5 3,646.2 104.0
Adjustment to (gain on) bargain purchase - - 6.3 (637.0)
Gain on debt extinguishment - - (3.1) (194.1)
Debtor in possession financing fees and payments on Backstop Commitment Agreement - - 40.0 -
Non-cash reorganization items, net - 3,487.3 436.4 -
Other 0.3 7.3 33.3 16.0
Changes in operating assets and liabilities, net of acquisition 10.3 68.5 (22.0) (52.5)
Contributions to pension plans and other post-retirement benefits (2.7) (22.5) (12.1) (13.2)
Net cash used in operating activities (26.2) (39.8) (251.7) (276.9)
INVESTING ACTIVITIES
Additions to property and equipment (50.2) (8.7) (93.8) (227.0)
Net proceeds from disposition of assets 25.1 30.1 51.8 17.7
Rowan cash acquired - - - 931.9
Maturities of short-term investments - - - 474.0
Purchases of short-term investments - - - (145.0)
Net cash provided by (used in) investing activities (25.1) 21.4 (42.0) 1,051.6
FINANCING ACTIVITIES
Issuance of first lien notes - 520.0 - -
Payments to Predecessor creditors - (129.9) - -
Borrowings on credit facility - - 596.0 215.0
Debtor in possession financing fees and payments on Backstop Commitment Agreement - - (40.0) -
Repayments of credit facility borrowings - - (15.0) (215.0)
Reduction of long-term borrowings - - (9.7) (928.1)
Purchase of noncontrolling interest - - (7.2) -
Debt solicitation fees - - - (9.5)
Cash dividends paid - - - (4.5)
Other - (1.4) (1.9) (10.2)
Net cash provided by (used in) financing activities - 388.7 522.2 (952.3)
Effect of exchange rate changes on cash and cash equivalents (0.1) (0.1) 0.1 (0.3)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (51.4) 370.2 228.6 (177.9)
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, BEGINNING OF YEAR 696.0 325.8 97.2 275.1
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, END OF YEAR $ 644.6 $ 696.0 $ 325.8 $ 97.2
The accompanying notes are an integral part of these consolidated financial statements.
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. We currently own an offshore drilling rig fleet of 56 rigs, with drilling operations in almost every major offshore market across six continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 40 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.
Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning 14 countries. The markets in which we operate include the Gulf of Mexico, South America, North Sea, the Middle East, Africa, Australia and Southeast Asia.
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.
See “Note 2 - Chapter 11 Proceedings” for additional details regarding the Chapter 11 Cases.
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.
Changes in Accounting Policies
Upon emergence from bankruptcy, we elected to change our accounting policies related to property and equipment as well as materials and supplies.
Prior to emergence from bankruptcy, we recorded our drilling rigs as a single asset with a useful life ascribed by the expected useful life of that asset. Upon emergence, we have identified the significant components of our drilling rigs and ascribed useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.
Historically, we recognized materials and supplies on the balance sheet when purchased and subsequently expensed items when consumed. Following emergence, 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.
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.
Reclassification
Certain previously reported amounts have been reclassified to conform to the current year presentation.
Pervasiveness of Estimates
The preparation of financial statements in conformity with U.S. 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.
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 $8.1 million and $13.4 million, and were included in Other, net, in our Consolidated Statements of Operations for the 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 $7.4 million, and were included in Other, net, in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor) and 2019 (Predecessor), respectively.
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, 2021 (Successor) and 2020 (Predecessor). 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, 2019. 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.
See "Changes in Accounting Policies" above for a discussion of the change in our accounting policy for property and equipment upon emergence from bankruptcy. 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 five 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 two 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 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 $756.5 million, $3.6 billion and $104.0 million, in the four months ended April 30, 2021 (Predecessor), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), respectively. See "Note 8 - 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, 2021 (Successor) or 2020 (Predecessor). However, we have historically used derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 10 - 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.
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 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 12 - 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 7 - 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 attributable to noncontrolling interests is presented separately in our Consolidated Statements of Operations. For the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), all income attributable to noncontrolling interest was from continuing operations.
Earnings Per Share
Basic income (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 warrants, restricted stock unit awards and performance stock unit awards and for the Predecessor includes the effect of all potentially dilutive stock options and excludes non-vested shares. In the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (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.
The following table is a reconciliation of loss from continuing operations attributable to our shares, or Legacy Valaris shares in the case of the Predecessor periods, used in our basic and diluted EPS computations (in millions).
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Loss from continuing operations attributable to Valaris $ (33.0) $ (4,467.0) $ (4,855.5) $ (198.0)
Income from continuing operations allocated to non-vested share awards (1)
- - - (0.1)
Loss from continuing operations attributable to Valaris shares $ (33.0) $ (4,467.0) $ (4,855.5) $ (198.1)
(1) Losses are not allocated to non-vested share awards. Due to the net loss position, potentially dilutive share awards are excluded from the computation of diluted EPS.
Anti-dilutive share awards totaling 600,000, 300,000, 400,000 and 300,000 for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), respectively, were excluded from the computation of diluted EPS.
The Predecessor previously had the 2024 Convertible Notes (as defined and more fully described in Note 9 "Debt") 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 years ended December 31, 2020 (Predecessor) or 2019 (Predecessor).
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. 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. On the Effective Date and pursuant to the plan of reorganization, the Company issued 5,645,161 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.
New Accounting Pronouncements
Recently adopted accounting pronouncements
Income Taxes - In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes ("Update 2019-12"), which removes certain exceptions for investments, intraperiod allocations and interim tax calculations and adds guidance to reduce complexity in accounting for income taxes. We were required to adopt the amended guidance in annual and interim periods beginning after December 15, 2020. The various amendments in Update 2019-12 are applied on a retrospective basis, modified retrospective basis and prospective basis, depending on the amendment. We adopted Update 2019-12 effective January 1, 2021 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 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 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. Our notes receivable with ARO, from which we generate interest income on a LIBOR-based rate, are impacted by the application of this standard. As the notes bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income in 2022 has already been determined. We expect to be able to modify the terms of our notes receivable 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.
Leases - In July 2021, the FASB issued ASU 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 are in the process of evaluating the impact this amendment will have on our consolidated financial statements.
Business Combinations - In October 2021, the FASB issued ASU 2021-08, “Accounting for Contracts Assets and Contract Liabilities from Contracts with Customers” (“Update 2021-08”). ASU 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. The ASU’s amendments are effective for fiscal years beginning after December 15, 2022, and interim periods within those fiscal years, with early adoption permitted. We will adopt Update 2021-08 in the period required and will apply it to any business combination completed subsequent to the adoption.
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 million capital injection by issuing the first lien secured notes (the "First Lien Notes"). See “Note 9 - 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.
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 28,859,900, 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 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 21,975,000, of Common Shares, and senior noteholders who agreed to backstop the Rights Offering received their pro rata share of approximately 2.63%, or 1,975,500 of Common Shares and approximately $48.8 million in First Lien Notes as a backstop premium;
•Certain Revolving Credit Facility lenders ("RCF Lenders") who participated in the Rights Offering received their pro rata share of approximately 0.7%, or 525,000 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 4,005,000 of 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 17,235,000 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;
•375,000 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 5,645,161 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 8,960,573 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 12 - Share Based Compensation" for more information on awards granted under the MIP after the Effective date.
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.
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.
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 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
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020
DIP facility fees $ - $ - $ 20.0
Professional fees 17.2 93.4 66.8
Contract items (1.7) 3.9 4.4
Reorganization items (fees) 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 $ 15.5 $ 3,584.6 $ 527.6
Reorganization items (fees) unpaid $ 0.8 $ 38.3 $ 61.2
Reorganization items (fees) paid $ 14.7 $ 59.0 $ 30.0
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
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 Newbuild Rigs, 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 ("WACC"), 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 long-term notes receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the note receivable using a discount rate based on a comparable yield with a country-specific risk premium.
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 Rigs
The fair value of the options to purchase Newbuild Rigs 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.
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) $ (.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
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 Rigs. 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 Rigs (5.5)
Fair value of options to purchase Newbuild Rigs 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 VALARIS DS-13 and VALARIS DS-14.
Additionally, upon effectiveness of the plan of reorganization, the amended agreement with the Shipyard provides the Company with the option to purchase the Newbuild Rigs. The reorganization adjustments include an asset that reflects the fair value of the option to purchase the Newbuild Rigs 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 Rigs $ (5.0)
Elimination of accrued post-petition holding costs associated with Newbuild Rigs (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 VALARIS DS-13 and VALARIS DS-14. 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 Rigs $ (49.9)
Elimination of accrued post-petition holding costs associated with Newbuild Rigs (4.7)
Elimination of lease liabilities associated with Newbuild Rigs (0.6)
$ (55.2)
The reorganization adjustments to other liabilities primarily relate to the elimination of construction contract intangible liabilities associated with the Newbuild Rigs. These construction contract intangible liabilities were recorded in purchase accounting for the original contracting entity. As the amended contract is 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 VALARIS DS-13 and VALARIS DS-14 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 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.
(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.
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.
(p) Property and equipment, net
Reflects the fresh start adjustments to historical amounts to record the estimated fair value of property and equipment.
(q) Long-term notes receivable from ARO
Reflects the fresh start adjustment to record the estimated fair value of the long-term notes receivable from ARO. The fair value of the long-term notes receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the note receivable 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.
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 the Rowan 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.
(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.
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 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 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, 2021 was between approximately 1 month and 3.5 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.
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 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. Costs incurred for capital upgrades are capitalized and depreciated over the useful life of the asset.
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.
Contract liabilities generally represent fees received for mobilization, capital upgrades or in the case of our 50/50 joint venture with Saudi Aramco, represent the difference between the amounts billed under the bareboat charter arrangements and lease revenues earned up to the respective period end. See “Note 6 - 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):
Successor Predecessor
December 31, 2021 December 31, 2020
Current contract assets $ 0.3 $ 1.4
Noncurrent contract assets $ - $ 0.4
Current contract liabilities (deferred revenue) $ 45.8 $ 57.6
Noncurrent contract liabilities (deferred revenue) $ 10.8 $ 14.3
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
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 expensed as incurred. Deferred contract costs were included in Other current assets and Other assets on our Consolidated Balance Sheets and totaled $31.4 million and $13.8 million as of December 31, 2021 (Successor) and December 31, 2020 (Predecessor), respectively. For the Successor, during the eight months ended December 31, 2021, amortization of such costs totaled $22.0 million. For the Predecessor, during the four months ended April 30, 2021, the year ended December 31, 2020 and the year ended December 31, 2019, amortization of such costs totaled $7.6 million, $42.1 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 $3.3 million and $8.4 million as of December 31, 2021 (Successor) and December 31, 2020 (Predecessor), respectively. For the Successor, during the eight months ended December 31, 2021, amortization of such costs totaled $0.7 million. For the Predecessor, during the four months ended April 30, 2021, the year ended December 31, 2020 and the year ended December 31, 2019, amortization of these costs totaled $3.1 million, $8.9 million and $10.3 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 6 - Equity Method Investment in ARO" for additional information on ARO and related arrangements. For the Successor, expected future amortization of our contract liabilities, or in the case of our contract liabilities related to our bareboat charter arrangements with ARO, the amount is reflected at the end of the lease term, and deferred costs recorded as of December 31, 2021 is set forth in the table below (in millions):
2022 2023 2024 2025 & Thereafter Total
Amortization of contract liabilities $ 45.8 $ 7.8 $ 1.2 $ 1.8 $ 56.6
Amortization of deferred costs $ 26.9 $ 6.9 $ 0.9 $ - $ 34.7
5. ROWAN TRANSACTION
On April 11, 2019 (the "Transaction Date"), we completed our combination with Rowan Companies Limited (formerly Rowan Companies plc) ("Rowan") pursuant to the Transaction Agreement (the "Rowan Transaction"). We were considered to be the acquirer for accounting purposes. As a result, Rowan's assets acquired and liabilities assumed in the Rowan Transaction were recorded at their estimated fair values as of the Transaction Date under the acquisition method of accounting. When the fair value of the net assets acquired exceeds the consideration transferred in an acquisition, the difference is recorded as a bargain purchase gain in the period in which the transaction occurs. As of March 31, 2020, we completed our fair value assessments of assets acquired and liabilities assumed. The provisional amounts recorded for assets and liabilities acquired were based on preliminary estimates of their fair values as of the Transaction Date and measurement period adjustments were recorded throughout the measurement period as provisional amounts were finalized.
Consideration
As a result of the Rowan Transaction, Rowan shareholders received 2.75 Legacy Valaris Class A Ordinary shares for each share of Rowan Class A ordinary share, representing a value of $43.67 per Rowan share based on a closing price of $15.88 per Legacy Valaris share on April 10, 2019, the last trading day before the Transaction Date. Total consideration delivered in the Rowan Transaction consisted of 88.3 million Legacy Valaris shares with an aggregate value of $1.4 billion, inclusive of $2.6 million for the estimated fair value of replacement employee equity awards. Upon closing of the Rowan Transaction, we effected a consolidation (being a reverse stock split under English law) where every four existing Class A ordinary shares, each with a nominal value of $0.10, were consolidated into one Class A ordinary share, each with a nominal value of $0.40 (the "Reverse Stock Split"). All Legacy Valaris share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split.
Bargain Purchase Gain (Predecessor)
The estimated fair values assigned to assets acquired net of liabilities assumed exceeded the consideration transferred, resulting in a bargain purchase gain at the Transaction date of $712.8 million primarily driven by the decline in our Legacy Valaris share price from $33.92 to $15.88 between the last trading day prior to the announcement of the Rowan Transaction and the Transaction Date. Measurement period adjustments were recorded to reflect new information obtained about facts and circumstances existing as of the Transaction Date and did not result from subsequent intervening events. The measurement period adjustments reflect changes in the estimated fair values of certain assets and liabilities, primarily related to long-lived assets, deferred income taxes and uncertain tax positions. The adjustments recorded resulted in a $75.8 million decline to the bargain purchase gain during 2019, resulting in a net bargain purchase gain of $637.0 million included in Other, net, in our Consolidated Statements of Operations for the year ended December 31, 2019 (Predecessor). Additionally, adjustments resulted in a $6.3 million decline to the bargain purchase gain during the first quarter of 2020, which is included in Other, net, in our Consolidated Statements of Operations for the year ended December 31, 2020 (Predecessor).
Transaction-related costs (Predecessor)
Transaction-related costs were expensed as incurred and consisted of various advisory, legal, accounting, valuation and other professional or consulting fees totaling $18.0 million for the year ended December 31, 2019 (Predecessor). These costs were included in General and administrative expense in our Consolidated Statements of Operations.
Revenues and Losses of Rowan
The amount of revenues and net losses of Rowan that are included from the Transaction Date to December 31, 2019 in the Company's Consolidated Statements of Operations for the Year ended December 31, 2019 (Predecessor) were $448.0 million and $122.7 million, respectively.
Unaudited Pro Forma Impact of the Rowan Transaction (Predecessor)
The following unaudited supplemental pro forma results present consolidated information as if the Rowan Transaction was completed on January 1, 2019. The pro forma results include, among others, (1) the amortization associated with acquired intangible assets and liabilities, (2) a reduction in depreciation expense for adjustments to property and equipment, (3) the amortization of premiums and discounts recorded on Rowan's debt, (iv) removal of the historical amortization of unrealized gains and losses related to Rowan's pension plans and (v) the amortization of basis differences in assets and liabilities of ARO. The pro forma results do not include any potential synergies or non-recurring charges that may result directly from the Rowan Transaction.
(unaudited)
(in millions, except per share amounts) Twelve Months Ended
December 31, 2019(1)
Revenues $ 2,240.5
Net loss $ (997.8)
Earnings per share - basic and diluted $ (3.82)
(1) Pro forma net loss and loss per share were adjusted to exclude an aggregate $108.1 million of transaction related and integration costs incurred during the year ended December 31, 2019. Additionally, pro forma net loss and loss per share exclude the measurement period adjustments and estimated gain on bargain purchase of $637.0 million recognized during the year ended December 31, 2019 (Predecessor).
6. EQUITY METHOD INVESTMENT IN ARO
Background
ARO, a company that owns and operates offshore drilling rigs in Saudi Arabia, was formed and commenced operations in 2017 pursuant to the terms of an agreement entered into by Rowan and Saudi Aramco to create a 50/50 joint venture ("Shareholder Agreement"). Pursuant to the Rowan Transaction, Valaris acquired Rowan's interest in ARO making Valaris a 50% partner. As of December 31, 2021, ARO owns seven jackup rigs, has ordered two newbuild jackup rigs and leases seven rigs from us through bareboat charter arrangements (the "Lease Agreements") whereby substantially all operating costs are incurred by ARO. At December 31, 2021, all of the leased rigs were operating under three-year drilling contracts, or related extensions, with Saudi Aramco. The seven rigs owned by ARO, previously purchased from Rowan and Saudi Aramco, are currently operating under contracts with Saudi Aramco for an aggregate 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, the Shareholder Agreement was amended ("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) reflect the impact of the lease modification on our rental revenues to reflect cumulative results through that period.
In connection with our 50/50 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. The first rig is expected to be delivered in the fourth quarter of 2022 and the second rig is expected either late in the fourth quarter of 2022 or in the first quarter of 2023. ARO is expected to place orders for two additional newbuild jackups in 2022. 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, on a proportionate basis.
The joint venture partners agreed 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, Rowan entered into (1) an agreement to provide certain back-office services for a period of time until ARO develops its own infrastructure (the "Transition Services Agreement"), and (2) an agreement to provide certain Rowan employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement"). These agreements remained in place subsequent to the Rowan Transaction. Pursuant to these agreements, we or 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. Additionally, our services to ARO under the Transition Services Agreement were completed as of December 31, 2020.
Summarized Financial Information
The operating revenues of ARO presented below reflect revenues earned under drilling contracts with Saudi Aramco for the seven 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. Substantially all costs incurred under the Transition Services Agreement are included in General and administrative. See additional discussion below regarding these related-party transactions.
Summarized financial information for ARO is as follows (in millions):
Year Ended December 31, 2021 Year Ended December 31, 2020 April 11, 2019 - December 31, 2019
Revenues $ 470.6 $ 549.4 $ 410.5
Operating expenses
Contract drilling (exclusive of depreciation) 362.3 388.2 280.2
Depreciation 65.2 54.8 40.3
General and administrative 17.8 24.2 27.1
Operating income 25.3 82.2 62.9
Other expense, net 13.4 26.7 28.6
Provision for income taxes 7.9 14.2 9.7
Net income $ 4.0 $ 41.3 $ 24.6
December 31, 2021 December 31, 2020
Cash and cash equivalents $ 270.8 $ 237.7
Other current assets 135.0 120.9
Non-current assets 775.8 804.0
Total assets $ 1,181.6 $ 1,162.6
Current liabilities $ 79.9 $ 70.8
Non-current liabilities 956.7 950.8
Total liabilities $ 1,036.6 $ 1,021.6
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 as of the Transaction Date. 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 that date. These basis differences primarily relate 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 Transaction Date. Additionally, in fresh start accounting, we have recorded our investment in ARO at its estimated fair value as of the Effective Date. Basis differences on that date primarily related to ARO's long-lived assets.
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 are combined with our 50% interest in ARO's net income. A reconciliation of those components is presented below (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 April 11, 2019 - December 31, 2019
50% interest in ARO net income (loss) $ (4.0) $ 6.0 $ 20.7 $ 12.3
Amortization of basis differences 10.1 (2.9) (28.5) (24.9)
Equity in earnings (losses) of ARO $ 6.1 $ 3.1 $ (7.8) $ (12.6)
Related-Party Transactions
Revenues recognized by us related to the Lease Agreements, Transition Services Agreement and Secondment Agreement are as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 April 11, 2019 - December 31, 2019
Lease revenue $ 35.4 $ 21.7 $ 52.2 $ 58.2
Secondment revenue 1.5 1.1 21.6 49.9
Transition Services revenue - - 1.3 17.3
Total revenue from ARO (1)
$ 36.9 $ 22.8 $ 75.1 $ 125.4
(1) All of the revenues presented above are included in our Other segment in our segment disclosures. See "Note 17- Segment Information" for additional information.
Amounts receivable from ARO related to the items above totaled $12.1 million and $21.6 million as of December 31, 2021 (Successor) and December 31, 2020 (Predecessor), respectively, and are included in Accounts receivable, net, on our Consolidated Balance Sheets.
We had $10.8 million and $38.3 million of contract liabilities and Accounts payable, respectively, related to the Lease Agreements as of December 31, 2021 (Successor). As of December 31, 2020 (Predecessor), we had $30.9 million of contract liabilities related to the Lease Agreements and no Accounts payable to ARO. 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, Rowan contributed cash to ARO in exchange for 10-year shareholder notes receivable based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. As of December 31, 2021 (Successor) and December 31, 2020 (Predecessor) the carrying amount of the long-term notes receivable from ARO was $249.1 million and $442.7 million respectively. The notes receivable were adjusted to fair value as of the Effective Date. The discount to the principal amount of $442.7 million is being amortized using the effective interest method to interest income over the remaining terms of the notes. The Shareholders’ Agreement prohibits the sale or transfer of the shareholder note to a third-party, except in certain limited circumstances. During the year ended December 31, 2020 (Predecessor), we recorded $10.2 million of employee benefit obligations against our long-term notes receivable from ARO. Interest is recognized as interest income in our Consolidated Statements of Operations. During the eight months ended December 31, 2021 (Successor), interest totaled $27.8 million of which $20.8 million pertains to non-cash amortization of discount on the shareholder notes. During the four months ended April 30, 2021 (Predecessor), interest totaled $3.5 million. Interest totaled $18.3 million for the year ended December 31, 2020 (Predecessor) and $16.8 million for the period from April 11, 2019 - December 31, 2019 (Predecessor). Interest amounts due were collected prior to the end of the year and we had no interest receivable from ARO as of December 31, 2021 (Successor) and December 31, 2020 (Predecessor).
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 shareholder notes receivable; and (3) other receivables and contract assets from ARO, partially offset by contract liabilities as well as payables to ARO.
Successor Predecessor
December 31, 2021 December 31, 2020
Total assets $ 348.1 $ 585.2
Less: total liabilities 49.1 30.9
Maximum exposure to loss $ 299.0 $ 554.3
7. FAIR VALUE MEASUREMENTS
The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis (in millions):
Quoted Prices in
Active Markets
for
Identical Assets
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Total
As of December 31, 2020
(Predecessor)
Supplemental executive retirement plan assets
$ 22.6 $ - $ - $ 22.6
Total financial assets $ 22.6 $ - $ - $ 22.6
Supplemental Executive Retirement Plan Assets
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. Assets held in a rabbi trust maintained for the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in Other assets, net, on our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). The fair value measurements of assets held in the SERP were based on quoted market prices. Pursuant to the plan of reorganization, the assets held in the rabbi trust maintained for the SERP were liquidated upon the Effective Date and used to satisfy the claims of creditors. 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. Net unrealized gains of $1.2 million, $3.2 million and $5.0 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), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), respectively.
Other Financial Instruments
The carrying values and estimated fair values of our debt instruments were as follows (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Carrying
Value Estimated
Fair
Value Carrying
Value (1)
Estimated
Fair
Value
Secured first lien notes due 2028 $ 545.3 $ 575.7 $ - $ -
6.875% Senior notes due 2020
- - 122.9 8.6
4.70% Senior notes due 2021
- - 100.7 4.5
4.875% Senior notes due 2022
- - 620.8 32.9
3.00% Exchangeable senior notes due 2024 (2)
- - 849.5 76.5
4.50% Senior notes due 2024
- - 303.4 13.7
4.75% Senior notes due 2024
- - 318.6 18.8
8.00% Senior notes due 2024
- - 292.3 12.9
5.20% Senior notes due 2025
- - 333.7 12.7
7.375% Senior notes due 2025
- - 360.8 20.9
7.75% Senior notes due 2026
- - 1,000.0 44.0
7.20% Debentures due 2027
- - 112.1 5.7
7.875% Senior notes due 2040
- - 300.0 21.0
5.40% Senior notes due 2042
- - 400.0 23.6
5.75% Senior notes due 2044
- - 1,000.5 38.0
5.85% Senior notes due 2044
- - 400.0 26.0
Amounts borrowed under Revolving Credit Facility (3)
- - 581.0 581.0
Total debt $ 545.3 $ 575.7 $ 7,096.3 $ 940.8
Less : Liabilities Subject to Compromise (4)
- - 7,096.3 940.8
Total long-term debt $ 545.3 $ 575.7 $ - $ -
(1) The carrying amount of debt instruments at December 31, 2020 represents the Predecessor's outstanding borrowings as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.
(2) For the Predecessor, the 3% exchangeable senior notes due 2024 (the "2024 Convertible Notes") were exchangeable into cash, our Class A ordinary shares or a combination thereof. The 2024 Convertible Notes were separated, at issuance, into their liability and equity components on our Consolidated Balance Sheet. The equity component was initially recorded to additional paid-in capital and as a debt discount and the discount was being amortized to interest expense over the life of the instrument. The carrying amount at December 31, 2020 represented the aggregate principal amount of these notes as of the Petition Date and was classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. The Predecessor discontinued accruing interest on these notes as of the Petition Date. The equity component was $220.0 million and was classified as Additional Paid-in Capital as of December 31, 2020. On the Effective Date, in accordance with the plan of reorganization, all outstanding obligations under the 2024 Convertible Notes were cancelled and the equity component was written off to retained earnings.
(3) In addition to the amount borrowed above, the Predecessor had $27.0 million in undrawn letters of credit issued under the Revolving Credit Facility as of December 31, 2020. On the Effective Date, in accordance with 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.
(4) As discussed in “Note 2 - Chapter 11 Proceedings” and “Note 3 - Fresh Start Accounting,” since the Petition Date and through the Effective Date, the Company operated as a debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the provisions of the Bankruptcy Code. Accordingly, all of our long-term debt obligations were presented as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). All unamortized debt discounts, premiums or issuance costs related to our long-term debt obligations were written off to reorganization items as of the Petition Date in 2020. Additionally, we discontinued accruing interest on our indebtedness as of the Petition Date.
The estimated fair values of the Successor's First Lien Notes and the Predecessor's Senior Notes were determined using quoted market prices, which are level 1 inputs. As of December 31, 2021 (Successor), the estimated fair value of our long-term notes receivable from ARO was $266.7 million and was estimated by using an income approach to value the forecasted cash flows attributed to the notes receivable using a discount rate based on comparable yield with a country-specific risk premium.
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, 2021 (Successor) and December 31, 2020 (Predecessor).
8. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Drilling rigs and equipment $ 886.9 $ 12,584.4
Work-in-progress 35.6 446.1
Other 34.5 178.8
$ 957.0 $ 13,209.3
Concurrent with our emergence from bankruptcy, we adopted fresh start accounting and adjusted the carrying value of our property and equipment to estimated fair value which included an adjustment to reconcile to our reorganization value. See "Note 3 - Fresh Start Accounting" for more information.
Work-in-progress as of December 31, 2020 (Predecessor) primarily consisted of approximately $418 million related to the construction of ultra-deepwater drillships VALARIS DS-13 and VALARIS DS-14.
Impairment of Long-Lived Assets
Predecessor
During the four months ended April 30, 2021, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters of $756.5 million. During the year ended December 31, 2020 and the year ended December 31, 2019, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters, jackups and spare equipment of $3.6 billion and $98.4 million, respectively. These pre-tax non-cash impairments are included in Loss on impairment in our Consolidated Statements of Operations.
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.
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 for certain floaters totaling $756.5 million. 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 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.
During 2019, together with the Rowan Transaction, and as a result of the evaluation of the strategy of the combined fleet, we determined that a triggering event occurred resulting in the performance of a fleet-wide recoverability test. We determined that estimated undiscounted cash flows were sufficient to cover the rigs carrying values and concluded that no impairments were necessary.
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 (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 our rig broker to market certain rigs. See “Note 9 - Debt" for additional details on restrictions on the sales of assets.
On a quarterly basis, we assess whether any rig meets the criteria established for held-for-sale classification on our balance sheet. All rigs 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.
Successor
In accordance with our business strategy described above, we sold VALARIS 22, VALARIS 37, VALARIS 100 and VALARIS 142, resulting in a pre-tax gain of $20.7 million during the eight months ending December 31, 2021 (Successor).
Predecessor
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 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. 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. During the fourth quarter of 2020, we classified our Australia office building as held-for-sale. The fair value, less cost to sale, of this asset was determined to be in excess of the carrying value and we concluded that there was no impairment for the asset.
Our Australia office building had a remaining aggregate carrying value of $2.3 million and is included in Other current assets, on our Consolidated Balance Sheet as of December 31, 2020. The office was subsequently sold in the first quarter of 2021 and we recognized an immaterial pre-tax gain during the four months ended April 30, 2021 (Predecessor).
During the third quarter of 2019, we decided to retire VALARIS 5006 and classified the rig as held-for-sale. We recognized a pre-tax, non-cash loss on impairment of $88.2 million, which represented the difference between the carrying value of the rig and related assets and their estimated fair value, less costs to sell. We subsequently sold the rig during the fourth quarter of 2019.
During the fourth quarter of 2019, we classified VALARIS 6002, VALARIS 68 and VALARIS 70 as held-for-sale. With the exception of VALARIS 70, we determined that the fair value, less costs to sell, based on each rig's estimated sales price, was in excess of the respective carrying value. Therefore, we concluded that there was no impairment for VALARIS 6002 and VALARIS 68. For VALARIS 70, we recognized a pre-tax impairment charge of $10.2 million. VALARIS 6002 and VALARIS 68 were subsequently sold in the first quarter of 2020 and VALARIS 70 was sold in the second quarter of 2020.
VALARIS 101 was sold and resulted in a gain of $5.3 million during the four months ended April 30, 2021 (Predecessor).
9. DEBT
The carrying value of our debt as of December 31, 2021 (Successor) and 2020 (Predecessor) consisted of the following (in millions):
Successor Predecessor
2021 2020(1)
Secured first lien notes due 2028 $ 545.3 $ -
6.875% Senior notes due 2020
- 122.9
4.70% Senior notes due 2021
- 100.7
4.875% Senior notes due 2022(2)
- 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(2)
- 318.6
8.00% Senior notes due 2024
- 292.3
5.20% Senior notes due 2025
- 333.7
7.375% Senior notes due 2025(2)
- 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(2)
- 400.0
5.75% Senior notes due 2044
- 1,000.5
5.85% Senior notes due 2044(2)
- 400.0
Amounts drawn under the Revolving Credit Facility (3)
- 581.0
Total debt $ 545.3 $ 7,096.3
Less: Liabilities Subject to Compromise - 7,096.3
Less: current maturities - -
Total long-term debt $ 545.3 $ -
(1) The carrying amounts above represent the aggregate principal amount of Senior Notes outstanding as well as outstanding borrowings under our Revolving Credit Facility as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). We discontinued accruing interest on our indebtedness following the Petition Date and all accrued interest as of the Petition Date is classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). Additionally, we incurred a net non-cash charge of $447.9 million to write off any unamortized debt discounts, premiums and issuance costs, including the amounts related to the 2024 Convertible Notes discussed below, which is included in Reorganization items, net on our Consolidated Statements of Operations for the year ended December 31,
2020 (Predecessor). On the Effective Date, in accordance with the plan of reorganization, all outstanding obligations under the Predecessor's Senior Notes, including the 2024 Convertible Notes, and the Revolving Credit Facility were cancelled and the holders thereunder received their pro rata share of certain Common Shares issued on the Effective Date. See below and "Note 2 - Chapter 11 Proceedings" for additional information.
(2) These senior notes were acquired in the Rowan Transaction.
(3) In addition to the amount borrowed above, we had $27.0 million in undrawn letters of credit issued under the Revolving Credit Facility.
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 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 million in cash in exchange for a $550 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: (i) 8.25% per annum, payable in cash; (ii) 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 (iii) 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. The first cash interest payment was made on November 1, 2021.
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% 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 (expressed as percentages of the principal amount), plus accrued and unpaid interest, if any, to, but excluding, the redemption date. The Company may also redeem the First Lien Notes, in whole or in part, at any time and from time to time on or after April 30, 2026 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if any, to, but excluding, the applicable 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: (i) incur, assume or guarantee additional indebtedness; (ii) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (iii) make investments; (iv) repay or redeem junior debt; (v) transfer or sell assets; (vi) enter into sale and lease back transactions; (vii) create, incur or assume liens; and (viii) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions.
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 association with the First Lien Notes that are being amortized into interest expense over the expected life of the 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 that will be used 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.
As of December 31, 2020 (Predecessor), we had no borrowings outstanding against our DIP Facility.
Predecessor Senior Notes
The commencement of the Chapter 11 Cases was considered an event of default under each series of 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, each series of our senior notes were cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization. The below paragraphs in this section contain further details about the inception or purchase of each of the Predecessor Senior Notes that were cancelled.
As a result of the Rowan Transaction, we acquired the following senior notes issued by Rowan Companies, LLC (formerly Rowan Companies, Inc.) ("RCI") and guaranteed by Rowan: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes due 2019, which were repaid at maturity in August 2019, (2) $620.8 million in aggregate principal amount of 4.875% 2022 Notes (the "4.875% 2022 Notes"), (3) $398.1 million in aggregate principal amount of 4.75% 2024 Notes (the "4.75% 2024 Notes"), (4) $500.0 million in aggregate principal amount of 7.375% 2025 Notes (the "7.375% 2025 Notes"), (5) $400.0 million in aggregate principal amount of 2042 Notes (the "2042 Notes"), and (6) $400.0 million in aggregate principal amount of 5.85% 2044 Notes (the "5.85% 2044 Notes"). On February 3, 2020, Rowan and RCI transferred substantially all their assets on a consolidated basis to Valaris plc, Valaris plc became the obligor on the notes and Rowan and RCI were relieved of their obligations under the notes and the related indenture.
On January 26, 2018, we issued $1.0 billion aggregate principal amount of unsecured 7.75% senior notes due 2026 (the "2026 Notes") at par, net of $16.5 million in debt issuance costs. Interest on the 2026 Notes was payable semiannually on February 1 and August 1 of each year.
During 2017, we exchanged $332.0 million aggregate principal amount of unsecured 8.00% senior notes due 2024 (the “8 % 2024 Notes”) for certain amounts of our outstanding senior notes due 2019, 2020 and 2021. Interest on the 8% 2024 Notes was payable semiannually on January 31 and July 31 of each year.
During 2015, we issued $700.0 million aggregate principal amount of unsecured 5.20% senior notes due 2025 (the “2025 Notes”) at a discount of $2.6 million and $400.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the “New 2044 Notes”) at a discount of $18.7 million in a public offering. Interest on the 2025 Notes was payable semiannually on March 15 and September 15 of each year. Interest on the New 2044 Notes was payable semiannually on April 1 and October 1 of each year.
During 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% senior notes due 2024 (the "2024 Notes") at a discount of $0.9 million and $625.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "Existing 2044 Notes") at a discount of $2.8 million. Interest on the 2024 Notes and the Existing 2044 Notes was payable semiannually on April 1 and October 1 of each year. The Existing 2044 Notes together with the New 2044 Notes, the "2044 Notes", were treated as a single series of debt securities under the indenture governing the notes.
During 2011, we issued $1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 (the “2021 Notes”) at a discount of $29.6 million in a public offering. Interest on the 2021 Notes was payable semiannually on March 15 and September 15 of each year.
Upon consummation of our acquisition of Pride International LLC ("Pride") during 2011, we assumed outstanding debt comprised of $900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020, $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Pride Notes"), and $500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 (collectively, with the Pride Notes, the "Acquired Notes"). Valaris plc fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes.
Certain of these senior notes allowed us to redeem these senior notes, either in whole in part, subject to the payment of certain “make whole” premiums. The indentures governing these senior notes contained customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contained certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.
Predecessor Debentures Due 2027
During 1997, Ensco International Incorporated issued $150.0 million of unsecured 7.20% Debentures due 2027 (the "Debentures"). Interest on the Debentures was payable semiannually on May 15 and November 15 of each year. We may redeem the Debentures, in whole or in part, at any time prior to maturity, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. During 2009, Valaris plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.
The Debentures and the indenture pursuant to which the Debentures were issued also contained customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The indenture also contained certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.
Predecessor 2024 Convertible Notes
In December 2016, Ensco Jersey Finance Limited, a wholly-owned subsidiary of Valaris plc, issued $849.5 million aggregate principal amount of 3.00% convertible senior notes due 2024 (the "2024 Convertible Notes") in a private offering. The 2024 Convertible Notes are fully and unconditionally guaranteed, on a senior, unsecured basis, by Valaris plc. Under the terms of the agreement, we had the option to settle our 2024 Convertible Notes in cash, shares or a combination thereof for the aggregate amount due upon conversion. However, the commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under the 2024 Convertible Notes. Any efforts to enforce payment obligations under the 2024 Convertible Notes, including any rights to require the repurchase by the Company of the 2024 Convertible Notes upon the NYSE delisting of the Class A ordinary shares, were automatically stayed as a result of the filing of the Chapter 11 Cases. Accordingly, the aggregate principal amount of 2024 Convertible Notes outstanding as well as associated 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, 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.
If our 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. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information regarding the impact to our EPS.
Interest on the 2024 Convertible Notes was payable semiannually on January 31 and July 31 of each year. The 2024 Convertible Notes will mature on January 31, 2024, unless exchanged, redeemed or repurchased in accordance with their terms prior to such date. Holders may exchange their 2024 Convertible Notes at their option any time prior to July 31, 2023 only under certain circumstances set forth in the indenture governing the 2024 Convertible Notes. On or after July 31, 2023, holders may exchange their 2024 Convertible Notes at any time. The exchange rate was 17.8336 shares per $1,000 principal amount of notes, representing an exchange price of $56.08 per share, and was subject to adjustment upon certain events. The 2024 Convertible Notes may not be redeemed by us except in the event of certain tax law changes.
The 2024 Convertible Notes were separated, at issuance, into their liability and equity components on our Consolidated Balance Sheet. The equity component was initially recorded to additional paid-in capital and as a debt discount and the discount was being amortized to interest expense over the life of the instrument. The carrying amount of the liability component was initially calculated by measuring the estimated fair value of a similar liability that did not include an associated conversion feature. The carrying amount of the equity component representing the conversion feature was initially determined by deducting the fair value of the liability component from the principal amount of the 2024 Convertible Notes. The difference between the carrying amount of the liability and the principal amount has been amortized to interest expense over the term of the 2024 Convertible Notes, together with the coupon interest, resulting in an effective interest rate of approximately 8.00% per annum. The carrying amount of the 2024 Convertible Notes at December 31, 2020 (Predecessor) represented the aggregate principal amount of these notes as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). The equity component was $220.0 million at December 31, 2020 (Predecessor) and remained in Additional paid-in capital. The equity component was not remeasured if we continued to meet certain conditions for equity classification. On the Effective Date, in accordance with the plan of reorganization, all outstanding obligations under the 2024 Convertible Notes were cancelled and the equity component was written off to retained earnings.
The costs related to the issuance of the 2024 Convertible Notes were initially allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were amortized to interest expense over the term of the notes and the issuance costs attributable to the equity component were recorded to Additional paid-in capital on our Consolidated Balance Sheet.
During the years ended December 31, 2020 and 2019 (Predecessor), we recognized $16.1 million and $25.5 million, respectively, associated with coupon interest. Amortization of debt discount and issuance costs were $21.4 million and $32.5 million for the years ended December 31, 2020 and 2019 (Predecessor), respectively. We discontinued accruing interest on these notes as of the Petition Date. Additionally, we incurred a net non-cash charge of $128.8 million to write off $119.5 million of unamortized debt discount and $9.3 million of unamortized debt issuance costs related to these notes, which is included in Reorganization items, net on our Consolidated Statements of Operations the year ended December 31, 2020 (Predecessor).
The indenture governing the 2024 Convertible Notes contained customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contained certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.
The 2021 Notes, 4.875% 2022 Notes, 4.75% 2024 Notes, 8.00% 2024 Notes, 2024 Notes, 2025 Notes, 7.375% 2025 Notes, 2026 Notes, 2042 Notes, 5.85% 2044 Notes, Existing 2044 Notes, the Pride Notes, the Debentures and 2024 Convertible Notes" together are the "Senior Notes".
Tender Offers and Open Market Repurchases (Predecessor)
In early March 2020, we repurchased $12.8 million of the 2021 Notes outstanding 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.
On June 25, 2019, we commenced cash tender offers for certain series of our senior notes. The tender offers expired on July 23, 2019, and we repurchased $951.8 million of our outstanding senior notes for an aggregate purchase price of $724.1 million. As a result of the transaction, we recognized a pre-tax gain from debt extinguishment of $194.1 million, net of discounts, premiums and debt issuance costs in other, net, in the Consolidated Statements of Operations.
Our tender offers and open market repurchases are summarized in the following table (in millions):
Predecessor
Aggregate Principal Amount Repurchased Aggregate Repurchase Price(1)
Year Ended December 31, 2020
4.70% Senior notes due 2021
$ 12.8 $ 9.7
Year Ended December 31, 2019
4.50% Senior notes due 2024
$ 320.0 $ 240.0
4.75% Senior notes due 2024
79.5 61.2
8.00% Senior notes due 2024
39.7 33.8
5.20% Senior notes due 2025
335.5 250.0
7.375% Senior notes due 2025
139.2 109.2
7.20% Senior notes due 2027
37.9 29.9
$ 951.8 $ 724.1
(1) Excludes accrued interest paid to holders of the repurchased senior notes.
Predecessor Revolving Credit Facility
Effective upon closing of the Rowan Transaction, our revolving credit facility was $1.6 billion.
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.
Interest Expense
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 and $428.3 million for the years ended December 31, 2020 and 2019 (Predecessor), respectively, which was net of capitalized interest of $1.3 million and $20.9 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.
10. 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). As a result, we no longer had derivative assets or liabilities on our Consolidated Balance Sheet as of December 31, 2020 (Predecessor). During the four months ended April 30, 2021 (Predecessor) and eight months ended December 31, 2021 (Successor), we did not enter into derivative contracts; therefore, we do not have derivative assets or liabilities on our Consolidated Balance Sheet as of December 31, 2021(Successor).
Historically we have 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):
Gain (Loss) Recognized in Other Comprehensive
Income ("OCI")
on Derivatives
(Effective Portion)
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Foreign currency forward contracts - - (5.4) 1.6
Total $ - $ - $ (5.4) $ 1.6
(Gain) Loss Reclassified from
AOCI into Income
(Effective Portion)(1)
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Interest rate lock contracts(2)
$ - $ - $ - $ 1.9
Foreign currency forward contracts(3)
- (5.6) (11.6) 6.4
Total $ - $ (5.6) $ (11.6) $ 8.3
(1)Changes in the fair value of cash flow hedges are recorded in AOCI. Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling expense, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transaction.
(2)Losses on interest rate lock derivatives reclassified from AOCI into income were included in Interest expense, net, in our Consolidated Statements of Operations.
(3)During the four months ended April 30, 2021 (Predecessor), $5.6 million of gains were reclassified from AOCI into Loss on impairment 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. During the year ended December 31, 2019 (Predecessor), $7.3 million of losses were reclassified from AOCI into Contract drilling expense and $0.9 million of gains were reclassified from AOCI into Depreciation expense in our Consolidated Statements of Operations.
We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. 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. Historically, we have occasionally entered into derivatives that hedged the fair value of recognized foreign currency denominated assets or liabilities but did not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally existed whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2021 (Successor) and December 31, 2020 (Predecessor) we did not have open derivative contracts to hedge against this risk.
Net losses of $0.2 million and $6.4 million associated with our derivatives not designated as hedging instruments were included in Other, net, in our Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 (Predecessor), respectively.
11. SHAREHOLDERS' EQUITY
Activity in our various shareholders' equity accounts for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the years ended December 31, 2020 (Predecessor) and 2019 (Predecessor) were as follows (in millions, except per share amounts):
Shares Par Value Additional
Paid-in
Capital Warrants Retained
Earnings (Deficit) AOCI Treasury
Shares Non-controlling
Interest
BALANCE, December 31, 2018 (Predecessor) 115.2 $ 46.2 $ 7,225.0 $ - $ 874.2 $ 18.2 $ (72.2) $ (2.6)
Net income (loss) - - - - (198.0) - - 5.8
Dividends paid ($0.04 per share) - - - - (4.5) - - -
Equity issuance in connection with the Rowan Transaction 88.0 35.2 1,367.5 - - - 0.1 -
Net changes in pension and other postretirement benefits - - - - - (21.7) - -
Distributions to noncontrolling interests - - - - - - - (4.5)
Equity issuance cost - - (0.6) - - - - -
Shares issued under share-based compensation plans, net 2.7 1.1 (1.3) - - - (0.7) -
Repurchase of shares - - - - - - (4.5) -
Share-based compensation cost - - 37.2 - - - - -
Net other comprehensive income - - - - - 9.7 - -
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) - -
Shares Par Value Additional
Paid-in
Capital Warrants Retained
Earnings (Deficit) AOCI Treasury
Shares Non-controlling
Interest
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)
Net income (loss) - - - - (33.0) - - 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 $ (33.0) $ (9.1) $ - $ 2.7
In connection with the Rowan Transaction on April 11, 2019, we issued 88.3 million Class A ordinary shares with an aggregate value of $1.4 billion. See "Note 5 - Rowan Transaction" for additional information.
Valaris Limited Share Capital
As of the Effective Date, the authorized share capital of Valaris Limited is $8.5 million divided into 700 million Common Shares of a par value of $0.01 each and 150 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 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 5,645,161 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 8,960,573 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 12 - Share Based Compensation" for information on equity awards granted under the MIP subsequent to the Effective Date.
12. 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, including Legacy Valaris's 2018 Long-Term Incentive Plan (the "2018 LTIP") as well as plans assumed in the Rowan Transaction ("Rowan LTIP") and in connection with the Atwood Merger (the “Atwood LTIP”, and together with the 2018 LTIP and the Rowan LTIP, the "Legacy LTIPs"). See "Note 2 - Chapter 11 Proceedings" for additional information.
In accordance with the plan of reorganization, Valaris Limited adopted the MIP as of the Effective Date and authorized and reserved 8,960,573 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, 2021, there were 7,493,135 shares available for issuance under the MIP.
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 at the vesting date, six-month anniversary following the termination of the director's service or a specific pre-determined date.
During the eight months ended December 31, 2021 (Successor), 1.1 million share unit awards were granted to our employees and non-employee directors pursuant to the MIP. No cash-settled awards were granted during this period under the MIP.
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. Deferred share awards were to be settled in cash, shares or a combination thereof at the discretion of the compensation committee.
During the four months ended April 30, 2021 (Predecessor), no share unit awards or cash-settled awards were granted.
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.
The following table summarizes share award and cash-settled award compensation expense recognized
(in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Contract drilling $ 1.6 $ 2.4 $ 10.7 $ 22.1
General and administrative 2.0 2.4 9.2 17.4
3.6 4.8 19.9 39.5
Tax benefit (0.2) (0.5) (1.8) (2.5)
Total
$ 3.4 $ 4.3 $ 18.1 $ 37.0
As of December 31, 2021, there was $19.9 million of total estimated unrecognized compensation cost related to Successor share awards, which has a weighted-average remaining vesting period of 1.7 years.
The following tables summarizes the value of share awards and cash-settled awards granted and vested:
Share Awards
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Weighted-average grant-date fair value of share awards granted (per share) (1)
$ 26.07 $ - $ 3.07 $ 11.50
Total fair value of share awards vested during the period (in millions) (2)
$ - $ 0.02 $ 3.26 $ 17.70
(1)During the four months ended April 30, 2021 (Predecessor), no share unit awards were granted.
(2)No share awards vested during the eight months ended December 31, 2021 (Successor).
Cash-Settled Awards
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Weighted-average grant-date fair value of share awards granted (per share) (1)
$ - $ - $ 0.75 $ -
Total fair value of share awards vested during the period (in millions) (2)
$ - $ - $ 0.22 $ 3.50
(1)During the eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and year ended December 31, 2019 (Predecessor) no cash-settled awards were granted.
(2)During the eight months ended December 31, 2021 (Successor), no cash-settled awards were vested.
The following table summarizes share awards and cash-settled awards activity for the four months ended April 30, 2021 (Predecessor) and eight months ended December 31, 2021 (Successor) (shares in thousands):
Share Awards Cash-settled Awards
Awards Weighted-Average
Grant-Date
Fair Value Awards Weighted-Average
Grant-Date
Fair Value
Share awards and cash-settled awards as of
December 31, 2020 (Predecessor)
2,982 $ 16.40 311 $ 22.74
Vested (195) 16.93 (25) 11.35
Forfeited (295) 32.98 (5) 29.18
Cancelled (2,492) 14.25 (281) 23.65
Share awards and cash-settled awards as of
April 30, 2021 (Predecessor)
- $ - - $ -
Share awards and cash-settled awards as of
May 1, 2021 (Successor)
- $ - - $ -
Granted 1,050 26.07 - -
Forfeited (192) 25.02 - -
Share awards and cash-settled awards as of
December 31, 2021 (Successor)
858 $ 26.30 - $ -
Performance Awards
Successor Awards
Under the Company's MIP, performance awards may be issued to our senior executive officers. The 2021 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.
The fair value of the 2021 performance awards granted during the 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 eight months ended December 31, 2021:
Expected price volatility 61 %
Expected dividend yield -
Risk-free interest rate 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 following table summarizes the performance award activity for the eight months ended December 31, 2021 (Successor) (shares in thousands):
Awards Weighted Average Grant Date Fair Value Price
Balance as of May 1, 2021 (Successor)
- -
Granted - Market-Based Objectives (1)
984 12.09
Granted - Performance-Based Objectives (1)
328 27.44
Total Granted 1,312 15.93
Forfeited - Market-Based Objectives (527) 11.04
Forfeited - Performance-Based Objectives (176) 25.02
Total Forfeited (703) 14.54
Balance as of December 31, 2021 (Successor)
609 17.53
(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 913,585.
During the eight months ended December 31, 2021 (Successor), we recognized of $0.7 million of compensation expense for performance awards, which was included in General and administrative expense in our Consolidated Statements of Operations.
As of December 31, 2021, there was $13.0 million of total estimated unrecognized compensation cost related to share awards, which has a weighted-average remaining vesting period of 2.6 years.
Predecessor Awards
Under the 2018 LTIP, performance awards were permitted to be issued to senior executive 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 grant-date fair value of performance awards granted during 2019 was $6.7 million. Subsequent to issuance, the 2020 performance awards were forfeited. The aggregate fair value of performance awards vested during 2020 and 2019 (Predecessor) totaled $5.2 million and $2.2 million, respectively.
During the years ended December 31, 2020 and 2019 (Predecessor) we recognized $1.0 million and $3.2 million of compensation expense for performance awards, respectively, 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 generally became exercisable in 33% increments over a three-year period and, to the extent not exercised, expired on the tenth anniversary of the date of grant. The exercise price of SARs granted under the Rowan LTIP equals the excess of the market value of the underlying shares on the date of exercise over the market value of the shares on date of grant multiplied by the number of shares covered by the SAR. The Predecessor had accounted for SARs as equity awards. No SARs had been granted since 2013 under the Rowan LTIP. As of December 31, 2020, SARs granted to purchase 426,049 shares were outstanding under the Rowan LTIP. During the four months ended April 30, 2021 (Predecessor), 106,408 of SARs expired unexercised, and as discussed above, in accordance with the plan of reorganization, the remaining outstanding SARs were cancelled.
Share Option Awards
Predecessor Awards
Share option awards granted to employees generally became exercisable in 25% increments over a four-year period or 33% increments over a three-year period or 100% after a four-year period and, to the extent not exercised, expired on either the seventh or tenth anniversary of the date of grant. The exercise price of options granted under the 2018 LTIP equaled the market value of the underlying shares on the date of grant. Excluding options assumed under the Atwood LTIP and Rowan LTIP, no options have been granted since 2011. As of December 31, 2020, options granted to purchase 318,377 shares were outstanding under the Legacy LTIPs. As discussed above, in accordance with the plan of reorganization, these outstanding options were cancelled.
13. PENSION AND OTHER POST-RETIREMENT BENEFITS
Prior to the Rowan Transaction, Rowan established various defined-benefit pension plans and a post-retirement health and life insurance plan that provide benefits upon retirement for certain full-time employees. The defined-benefit pension plans include: (1) the Rowan Pension Plan; (2) Restoration Plan of Rowan Companies, Inc. (the “Rowan SERP”); (3) the Norway Onshore Plan; and (4) the Norway Offshore Plan. The Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc. (the “Retiree Medical Plan”) provides post-retirement health and life insurance benefits. On November 27, 2017, Rowan purchased annuities to cover post-65 retiree medical benefits for current retirees as of the purchase date. The annuity purchase settled post-65 medical benefits (i.e., Health Reimbursement Account, or “HRA”, amounts) for affected participants, with the insurer taking responsibility for all benefit payments on and after January 1, 2019.
As a result of the Rowan Transaction, we assumed these plans and obligations, which were remeasured as of the Transaction Date. Each of the plans has a benefit obligation that exceeds the fair value of plan assets. The most significant of the assumed plans is the Rowan Pension Plan. Prior to the Transaction Date, Rowan amended the Rowan Pension Plan to freeze the plan as to any future benefit accruals. As a result, eligible employees no longer receive pay credits in the pension plan and newly hired employees are not eligible to participate in the pension plan.
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.
The following table presents the changes in benefit obligations and plan assets 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) and the funded status and weighted-average assumptions used to determine the benefit obligation at the measurement date (dollars in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020
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 $ 826.1 $ 14.8 $ 840.9 $ 886.7 $ 15.9 $ 902.6 $ 832.4 $ 16.1 $ 848.5
Interest cost 15.3 0.3 15.6 6.5 0.1 6.6 24.9 0.5 25.4
Service cost - - - - - - .1 - 0.1
Actuarial loss (gain) 20.6 (4.2) 16.4 (55.0) (1.0) (56.0) 97.8 (0.1) 97.7
Plan settlements (25.9) - (25.9) - - - (6.6) - (6.6)
Plan curtailments - - - - - - (3.3) - (3.3)
Plan amendments 0.2 - 0.2 - - - - - -
Benefits paid (25.7) (0.3) (26.0) (12.1) (0.2) (12.3) (58.6) (0.6) (59.2)
Net transfer in/(out) (including the effect of any business combinations/divestitures) 17.3 5.0 22.3 - - - - - -
BALANCE at the end of the period $ 827.9 $ 15.6 $ 843.5 $ 826.1 $ 14.8 $ 840.9 $ 886.7 $ 15.9 $ 902.6
Plan assets
Fair value, at the beginning of the period $ 652.0 $ - $ 652.0 $ 603.1 $ - $ 603.1 $ 598.9 $ - $ 598.9
Actual return 31.8 - 31.8 38.5 - 38.5 57.9 - 57.9
Employer contributions 2.4 - 2.4 22.5 - 22.5 11.5 - 11.5
Plan settlements (25.9) - (25.9) - - - (6.6) - (6.6)
Benefits paid (25.7) - (25.7) (12.1) - (12.1) (58.6) - (58.6)
Fair value, at the end of the period $ 634.6 $ - $ 634.6 $ 652.0 $ - $ 652.0 $ 603.1 $ - $ 603.1
Net benefit liabilities $ 193.3 $ 15.6 $ 208.9 $ 174.1 $ 14.8 $ 188.9 $ 283.6 $ 15.9 $ 299.5
Amounts recognized in Consolidated Balance Sheet:
Accrued liabilities $ (3.8) $ (1.1) $ (4.9) $ (1.4) $ (1.4) $ (2.8) $ (1.5) $ (1.4) $ (2.9)
Other liabilities (long-term) (189.5) (14.5) (204.0) (172.7) (13.4) (186.1) (282.1) (14.5) (296.6)
Net benefit liabilities $ (193.3) $ (15.6) $ (208.9) $ (174.1) $ (14.8) $ (188.9) $ (283.6) $ (15.9) $ (299.5)
Accumulated contributions in excess of (less than) net periodic benefit cost $ (180.0) $ (19.8) $ (199.8) $ (174.1) $ (14.8) $ (188.9) $ (179.6) $ (15.8) $ (195.4)
Amounts not yet reflected in net periodic benefit cost:
Actuarial gain (loss) (13.1) 4.2 (8.9) - - - (104.0) $ (0.1) (104.1)
Prior service credit (cost) (0.2) - (0.2) - - - - - -
Total accumulated other comprehensive income (loss) $ (13.3) $ 4.2 $ (9.1) $ - $ - $ - $ (104.0) $ (0.1) $ (104.1)
Net benefit liabilities $ (193.3) $ (15.6) $ (208.9) $ (174.1) $ (14.8) $ (188.9) $ (283.6) $ (15.9) $ (299.5)
Weighted-average assumptions:
Discount rate 2.73 % 2.72 % 2.84 % 2.73 % 2.30 % 2.19 %
Cash balance interest credit rate 3.05 % N/A 2.94 % N/A 2.94 % N/A
The unfunded obligation increased by $20.0 million as of December 31, 2021 when compared to the unfunded obligation as of April 30, 2021. The increase was primarily attributable to the unfunded obligation under the SERP, having a balance of $16.2 million at December 31, 2021, which was transferred in as of July 1, 2021. Additionally, a decline in the discount rate and the impact of updated census data contributed to the increase in the unfunded obligation in the amount of $9.2 million and $13.2 million, respectively. This was partially offset by higher than expected return on plan assets of $7.1 million, and employer contributions of $2.4 million during the eight months ended December 31, 2021.
The unfunded obligation decreased by $110.6 million as of April 30, 2021 when compared to the unfunded obligation as of December 31, 2020. The decrease was primarily attributable to the remeasurement of the pension and other post-retirement benefit plans at the Effective Date in fresh start accounting of $82.7 million due to an increase in the discount rate and higher than expected return on plan assets of approximately$56 million and $26 million, respectively. See "Note 3 - Fresh Start Accounting" for more information on the remeasurement of the pension and other post-retirement benefit plans. Additionally, employer contributions of $22.5 million made during the four months ended April 30, 2021 (Predecessor) drove a further decline in the unfunded obligation.
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 obligations, which are presented below for all plans in the aggregate at December 31, 2021 and 2020, are based on services rendered to date, but exclude the effect of future salary increases (in millions):
Successor Predecessor
2021 2020
Accumulated benefit obligation $ 843.5 $ 902.6
The components of net periodic pension, retiree medical cost and the weighted-average assumptions used to determine net periodic pension and retiree medical cost were as follows (dollars in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 April 11, 2019 - December 31, 2019
Service cost (1)
$ - $ - 0.1 1.5
Interest cost (2)
15.6 6.6 25.4 21.3
Expected return on plan assets (2)
(24.7) (12.1) (36.5) (27.1)
Curtailment gain recognized (2)
- - (3.3) -
Settlement (gain) loss recognized (2)
0.4 - (0.3) -
Amortization of net loss (2)
- 0.1 - -
Net periodic pension and retiree medical cost (income) $ (8.7) $ (5.4) $ (14.6) $ (4.3)
Discount rate 2.84 % 2.30 % 3.16 % 3.82 %
Expected return on assets 6.03 % 6.03 % 6.48 % 6.70 %
Cash balance interest credit rate 2.94 % 2.94 % 3.29 % 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. The settlement threshold was reached for the Rowan Pension Plan and we recognized a settlement charge of $0.4 million in our Consolidated Statements of Operations during the eight months ended December 31, 2021 (Successor).
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 should lower pension contribution requirements over the next few years. As a result, we did not make contributions to certain plans in 2021. However, we currently expect to contribute approximately $3.8 million to our pension plans and to directly pay other post-retirement benefits of approximately $1.2 million in 2022. 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 over the life of the plans a return equal to the plans' expected investment return or the inflation rate plus 3%, whichever is greater, to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities, to maintain liquidity sufficient to pay benefits when due, and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.
Target allocations among asset categories and the fair value of each category of plan assets as of December 31, 2021 and 2020, 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, 2021 (Successor)
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 - -
Group annuity contracts - - - -
Total $ 634.6 $ 78.8 $ 555.8 $ -
December 31, 2020 (Predecessor)
Equities:
53% to 69%
U.S. large cap 22% to 28%
$ 151.9 $ - $ 151.9 $ -
U.S. small cap
4% to 10%
48.1 - 48.1 -
International all cap
21% to 29%
158.5 - 158.5 -
International small cap
2% to 8%
37.0 - 37.0 -
Real estate equities
0% to 13%
53.5 - 53.5 -
Fixed income: 25% to 35%
Aggregate 9% to 19%
74.3 - 74.3 -
Core plus 9% to 19%
75.8 75.8 - -
Cash and equivalents 0% to 10%
4.0 4.0 - -
Group annuity contracts - - - -
Total $ 603.1 $ 79.8 $ 523.3 $ -
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 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 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 both the aggregate and core plus fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in non-U.S. securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. Group annuity contracts are invested in a combination of equity, real estate, bond and other investments in connection with a pension plan in Norway.
The following is a description of the valuation methodologies used for the pension plan assets as of December 31, 2021:
•Fair values of all U.S. equity securities, the international all cap equity securities and aggregate fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.
•Fair value of international small cap equity securities categorized as Level 2 were held in a limited partnership fund which was valued monthly based on a net asset value.
•The real estate equities categorized as Level 2 were held in two accounts (a commingled fund and a limited partnership). The assets in the commingled fund were valued monthly based on a net asset value and the assets in 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.
•Fair value of mutual fund investments in core plus fixed income securities categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.
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 6.26% at December 31, 2021 (Successor) from 6.03% at December 31, 2020 (Predecessor).
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,
2022 $ 42.7 $ 1.2
2023 42.3 1.2
2024 42.3 1.2
2025 41.8 1.1
2026 41.2 1.0
2027 through 2030 200.2 4.2
Savings Plans
We have savings plans, (the Ensco Savings Plan, the Valaris Multinational Savings Plan, the Valaris Limited Retirement Plan and the frozen RDIS International Savings Plan), which cover eligible employees as defined within each plan. During 2020, the plan assets of the legacy Rowan savings plans (the Rowan Companies, Inc. Savings & Investment Plan and the Rowan Drilling UK Pension Scheme) were transferred to the Ensco Savings Plan and the Valaris Limited Retirement Plan, respectively. The Ensco Savings Plan includes a 401(k) savings plan feature, which allows eligible employees to make tax-deferred contributions to the plans. The Valaris Limited Retirement Plan allows eligible employees to make tax-deferred contributions to the plan. Contributions made to the Valaris Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.
Historically, we made matching cash contributions to the plans. The legacy Ensco plans previously matched 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary, where the legacy Rowan plans also provided up to a 5% match of eligible salary; however, depending on the plan and the tier, the match percentage could vary. Matching contributions totaled $8.8 million and $18.7 million for the years ended December 31, 2020 and 2019 (Predecessor), respectively. Effective August 1, 2020, in light of the then current economic environment, we suspended employer matching contributions for the Ensco Savings Plan and the Valaris Multinational Savings Plan. In addition, effective December 1, 2020, the matching contributions in the Valaris Limited Retirement Plan were reduced. Employer contributions were reinstated effective January 1, 2022 whereby 100% of the amount contributed by the employee is matched up to a maximum of 4% of eligible salary.
14. INCOME TAXES
We generated profits of $253.4 million and $373.1 million, losses of $51.0 million and profits of $39.0 million before income taxes in the U.S. for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively. We generated losses of $245.2 million, $4.8 billion, $5.1 billion and $102.8 million before income taxes in non-U.S. jurisdictions for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively.
The components of our provision for income taxes are summarized as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Current income tax expense (benefit):
U.S. $ 5.5 $ - $ (135.3) $ 31.3
Non-U.S. 53.2 34.4 (18.4) 73.2
58.7 34.4 (153.7) 104.5
Deferred income tax expense (benefit):
U.S. (6.6) - (92.9) 19.7
Non-U.S. (14.7) (18.2) (12.8) 4.2
(21.3) (18.2) (105.7) 23.9
Total income tax expense (benefit) $ 37.4 $ 16.2 $ (259.4) $ 128.4
U.S. Tax Reform and CARES Act
The U.S. Tax Cuts and Jobs Act ("U.S. tax reform") was enacted on December 22, 2017 and introduced significant changes to U.S. income tax law, effective January 1, 2018. Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, the U.S. Treasury Department continued finalizing rules associated with U.S. tax reform during 2018 and 2019. During 2019, we recognized a tax expense of $13.8 million associated with final rules issued related to U.S. tax reform.
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.
Deferred Taxes
The components of deferred income tax assets and liabilities are summarized as follows (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Deferred tax assets:
Net operating loss carryforwards $ 2,293.5 $ 2,272.2
Property and equipment 1,361.6 -
Foreign tax credits 105.7 171.2
Interest limitation carryforwards 74.8 221.2
Employee benefits, including share-based compensation 51.2 81.6
Premiums on long-term debt 9.7 115.7
Other 15.4 6.8
Total deferred tax assets 3,911.9 2,868.7
Valuation allowance (3,829.0) (2,787.7)
Net deferred tax assets 82.9 81.0
Deferred tax liabilities:
Property and equipment - (40.9)
Other (14.5) (11.2)
Total deferred tax liabilities (14.5) (52.1)
Net deferred tax asset $ 68.4 $ 28.9
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, 2021 (Successor), we had gross deferred tax assets of $2.3 billion relating to $10.0 billion of NOL carryforwards, $105.7 million of U.S. foreign tax credits (“FTCs”), and $74.8 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 $9.1 billion that do not expire and $807.5 million that will expire, if not utilized, between 2022 and 2040. Deferred tax assets for NOL carryforwards as of December 31, 2021 (Successor) include $1.4 billion, $599.2 million, $76.4 million, and $56.4 million pertaining to NOL carryforwards in Luxembourg, the United States, Switzerland, and the U.K., respectively. The U.S. FTCs expire between 2022 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 $3.8 billion valuation allowance as of December 31, 2021 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.
Certain components of deferred tax assets and liabilities as of December 31, 2021 (Successor) have changed significantly from December 31, 2020 (Predecessor) due to the impacts of fresh start accounting, Switzerland tax reform, and other tax attribute reductions resulting from restructurings due to and in connection with the emergence from bankruptcy. During the eight months ended December 31, 2021, we recognized a $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 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, the Successor Company and our parent company, 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. Valaris plc, the Predecessor Company and our former parent company, 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.
Our consolidated effective income tax rate for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the year ended December 31, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), respectively, differs from the Bermuda and U.K. statutory income tax rates as follows:
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Bermuda (Successor)/ U.K. (Predecessor) statutory income tax rate
- % 19.0 % 19.0 % 19.0 %
Asset impairments - (3.2) (12.5) (31.0)
Non-Bermuda (Successor) taxes
376.0 - - -
Non-U.K. (Predecessor) taxes
- 1.0 (2.8) (280.9)
Resolution of prior year items
387.9 (0.4) 1.8 12.3
Switzerland Tax Reform (188.3) - - -
Valuation allowance (119.5) (1.8) (1.5) (145.1)
U.S. tax reform and U.S. CARES Act - - 2.4 (21.6)
Bargain purchase gain - - - 189.7
Debt repurchases - - - 48.7
Other - (15.0) (1.3) 7.6
Effective income tax rate 456.1 % (0.4) % 5.1 % (201.3) %
Our eight months ended December 31, 2021 (Successor) consolidated effective income tax rate includes $15.3 million associated with the impact of various discrete items, including $30.7 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.
Our 2019 consolidated effective income tax rate includes $2.3 million associated with the impact of various discrete tax items, including $28.3 million of tax expense associated with final rules related to U.S. tax reform, gains on repurchase of debt and settlement proceeds, partially offset by $26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales.
Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) were 387.7% and (12.9)%, respectively. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020 and 2019 (Predecessor) were (7.6)% and (14.6)%, 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.
As discussed in "Note 9 - Debt", on February 3, 2020, Rowan and RCI transferred substantially all their assets and liabilities to Valaris plc and Valaris plc became the obligor on the 4.875% 2022 Notes, 2042 Notes, 7.375% 2025 Notes, 4.75% 2024 Notes and 5.85% 2044 Notes. 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, 2021 (Successor), we had $234.3 million of unrecognized tax benefits, of which $212.2 million was included in Other liabilities on our Consolidated Balance Sheet, $21.1 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.
As of December 31, 2020 (Predecessor), we had $237.7 million of unrecognized tax benefits, of which $213.0 million was included in Other liabilities on our Consolidated Balance Sheet, $20.7 million, which is associated with tax positions taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets and $4.0 million was presented as a reduction of long-term income tax receivable.
If recognized, $208.9 million of the $234.3 million unrecognized tax benefits as of December 31, 2021 (Successor) would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits 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 (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020
Balance, beginning of period $ 235.4 $ 237.7 $ 296.7
Increase in unrecognized tax benefits as a result of tax positions taken during prior years 33.8 2.9 22.4
Lapse of applicable statutes of limitations (20.2) (0.2) (13.2)
Impact of foreign currency exchange rates (10.5) (17.6) 9.0
Increases in unrecognized tax benefits as a result of tax positions taken during the current year 6.9 12.6 12.8
Settlements with taxing authorities (6.6) - (0.7)
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years (4.5) - (89.3)
Balance, end of period $ 234.3 $ 235.4 $ 237.7
Accrued interest and penalties totaled $108.0 million and $73.1 million as of December 31, 2021 (Successor) and 2020 (Predecessor), respectively, and were included in Other liabilities on our Consolidated Balance Sheets. We recognized a net expense of $21.3 million, $13.5 million, $13.8 million and $5.7 million associated with interest and penalties during the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively. Interest and penalties are included in Current income tax expense in our Consolidated Statements of Operations.
Three of our subsidiaries file 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 2015, 2017 and subsequent years. None of these examinations are expected to have an 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 eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), resulting in net income tax benefits, inclusive of interest and penalties, of $17.9 million, $0.2 million, $4.3 million and $5.3 million, respectively.
Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2022. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $4.0 million, inclusive of $1.4 million of accrued interest and penalties, all of which would impact our consolidated effective income tax rate if recognized.
Tax Assessments
Predecessor
During 2019, the Luxembourg tax authorities issued aggregate tax assessments totaling approximately €142.0 million (approximately $161.5 million converted using the current period-end 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 using the current period-end 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 using the current period-end 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 using the current period-end exchange rates) and €2.0 million (approximately $2.3 million converted using the current period-end 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, we de-recognized the remaining liability for uncertain tax position balance of €14.0 million (approximately $15.9 million converted using the current period-end 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 $73.4 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 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have an $18.0 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2021 (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, 2021 (Successor), the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $279.5 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, 2021 (Successor).
15. COMMITMENTS AND CONTINGENCIES
Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14. On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy. The amendments 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 rigs on or before December 31, 2023. Under the amended agreements, the purchase price for the rigs are estimated to be approximately $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. The amended agreements removed any parent company guarantee.
Indonesian Well-Control Event
In July 2019, a well being drilled offshore Indonesia by one of our jackup rigs experienced a well-control event requiring the cessation of drilling activities. In February 2020, the rig resumed operations. Indonesian authorities initiated an investigation into the event and have contacted the customer, us and other parties involved in drilling the well for additional information. We cooperated with the Indonesian authorities. We cannot predict the scope or ultimate outcome of this investigation. If the Indonesian authorities determine that we violated local laws in connection with this matter, we could be subject to penalties including environmental or other liabilities, which may have a material adverse impact on us.
ARO Funding Obligations
In connection with our 50/50 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. The first rig is expected to be delivered in the fourth quarter of 2022 and the second rig is expected either late in the fourth quarter of 2022 or in the first quarter of 2023. ARO is expected to place orders for two additional newbuild jackups in 2022. 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, on a proportionate basis.
The joint venture partners agreed 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.
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.
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, 2021 (Successor) totaled $36.5 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, 2021 (Successor), we had collateral deposits in the amount of $31.1 million with respect to these agreements.
16. 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
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Long-term operating lease cost $ 12.9 $ 9.1 $ 23.3 $ 29.5
Short-term operating lease cost 15.3 7.0 19.2 12.2
Sublease income (0.3) (0.1) (2.3) (2.4)
Total operating lease cost $ 27.9 $ 16.0 $ 40.2 $ 39.3
Supplemental balance sheet information related to our operating leases is as follows (in millions, except lease term and discount rate):
Successor Predecessor
December 31, 2021 December 31, 2020
Operating lease right-of-use assets $ 20.5 $ 35.8
Current lease liability $ 10.0 $ 15.7
Long-term lease liability 12.5 21.6
Total operating lease liabilities $ 22.5 $ 37.3
Weighted-average remaining lease term (in years) 4.8 4.3
Weighted-average discount rate (1)
7.27 % 8.24 %
(1)Represents our estimated incremental borrowing cost on a secured basis for similar terms as the underlying leases.
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 and 2019 (Predecessor), cash paid for amounts included in the measurement of our operating lease liabilities were $23.5 million and $29.9 million, respectively.
Maturities of lease liabilities as of December 31, 2021 (Successor) were as follows (in millions):
2022 $ 11.3
2023 3.1
2024 2.2
2025 2.0
2026 2.0
Thereafter 6.8
Total lease payments $ 27.4
Less imputed interest (4.9)
Total $ 22.5
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 on 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 the office lease rejections, we reduced our right-of-use asset by a total of $10.5 million and lease liability by a total of $20.4 million and recognized a net gain in Reorganization items of $9.8 million which includes the write off of associated leasehold improvements. Additionally, in connection with the lease rejections, during the year ended December 31, 2020 (Predecessor), we amended the terms of the lease for our corporate headquarters in Houston, Texas. The amendment reduced the associated right-of-use asset by $6.4 million and lease liability by $10.4 million and we recognized a net gain in Reorganization items of $1.7 million which includes the write-off of associated leasehold improvements during the year ended December 31, 2020 (Predecessor).
During the year ended December 31, 2019 (Predecessor), we recorded lease impairments of $5.6 million related to the impairment of the right-of-use assets associated with an office space and a leased yard facility that were abandoned due to the consolidation of certain corporate offices and leased facilities.
17. 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, the Secondment Agreement and the Transition Services Agreement. Floaters, Jackups and ARO are also reportable segments.
Upon emergence, we ceased allocation of our onshore support costs included within Contract drilling expenses to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items”. We have adjusted the historical periods to conform with current period presentation. 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." Substantially all of the expenses incurred associated with our Transition Services Agreement are included in General and administrative under "Reconciling Items" in the table set forth below. 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 6 - Equity Method Investment in ARO" for additional information on ARO and related arrangements.
Segment information for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively are presented below (in millions).
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 (172.3) 728.7
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 $ (129.4) $ (11.9)
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
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
Year Ended December 31, 2019 (Predecessor)
Floaters Jackups ARO Other Reconciling Items Consolidated Total
Revenues $ 1,014.4 $ 834.6 $ 410.5 $ 204.2 $ (410.5) $ 2,053.2
Operating expenses
Contract drilling (exclusive of depreciation) 785.0 711.3 280.2 111.0 (79.7) 1,807.8
Loss on impairment 88.2 10.2 - - 5.6 104.0
Depreciation 362.3 203.3 40.3 25.5 (21.7) 609.7
General and administrative - - 27.1 - 161.8 188.9
Equity in losses of ARO - - - - (12.6) (12.6)
Operating income (loss) $ (221.1) $ (90.2) $ 62.9 $ 67.7 $ (489.1) $ (669.8)
Property and equipment, net $ 10,073.1 $ 4,322.7 $ 650.7 $ 620.9 $ (570.5) $ 15,096.9
Capital expenditures $ 31.4 $ 184.6 $ 27.5 $ - $ (16.5) $ 227.0
Information about Geographic Areas
As of December 31, 2021 (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 33 jackup rigs which were deployed in various locations and our Other segment consisted of seven jackup rigs which are leased to our 50/50 joint venture with Saudi Aramco.
As of December 31, 2021 (Successor), the geographic distribution of our and ARO's drilling rigs was as follows:
Floaters Jackups Other Total Valaris ARO
North & South America 6 6 - 12 -
Europe & the Mediterranean 6 12 - 18 -
Middle East & Africa 2 8 7 17 7
Asia & Pacific Rim 2 7 - 9 -
Total 16 33 7 56 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 drillships, VALARIS DS-13 and VALARIS DS-14, 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.
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. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined.
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
Successor Predecessor
December 31, 2021 December 31, 2020 December 31, 2019
United States $ 152.1 $ 1,811.9 $ 2,972.4
Spain 145.8 2,122.6 3,012.4
United Kingdom 142.4 2,584.0 1,210.5
Saudi Arabia 75.2 1,183.7 1,259.3
Other countries(1)
395.9 3,294.1 6,700.4
Total $ 911.4 $ 10,996.3 $ 15,155.0
(1)Other countries includes countries where individually we had long-lived assets representing less than 10% of total long-lived assets
18. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net, consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Trade $ 296.8 $ 260.1
Income tax receivables 151.1 190.6
Other 12.7 14.7
460.6 465.4
Allowance for doubtful accounts (16.4) (16.2)
$ 444.2 $ 449.2
Other current assets consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Prepaid taxes $ 44.4 $ 32.9
Deferred costs 26.9 17.4
Prepaid expenses 23.1 43.4
Materials and supplies - 279.4
Other 23.4 13.4
$ 117.8 $ 386.5
Other assets consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Tax receivables $ 64.8 $ 66.8
Deferred tax assets 59.7 21.9
Right-of-use assets 20.5 35.8
Supplemental executive retirement plan assets - 22.6
Other 31.0 29.1
$ 176.0 $ 176.2
Accrued liabilities and other consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Personnel costs $ 64.6 $ 95.6
Income and other taxes payable 45.7 50.8
Deferred revenue 45.8 57.6
Lease liabilities 10.0 15.7
Accrued interest 7.6 -
Other 22.5 30.7
$ 196.2 $ 250.4
Other liabilities consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Unrecognized tax benefits (inclusive of interest and penalties) $ 320.2 $ 286.1
Pension and other post-retirement benefits 204.0 296.6
Intangible liabilities - 50.4
Customer payable - 35.5
Other 56.9 93.8
$ 581.1 $ 762.4
Accumulated other comprehensive income (loss) consisted of the following (in millions):
Successor Predecessor
December 31, 2021 December 31, 2020
Pension and other post-retirement benefits $ (9.1) $ (98.2)
Currency translation adjustment - 6.5
Derivative instruments - 5.6
Other - (1.8)
$ (9.1) $ (87.9)
Consolidated Statements of Operations Information
Repair and maintenance expense related to continuing operations was as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Repair and maintenance expense $ 76.3 $ 48.4 $ 200.4 $ 303.7
Other, net, consisted of the following (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Net gain on sale of property $ 21.2 $ 6.0 $ 11.8 $ 1.8
Net periodic pension income, excluding service cost 8.7 5.4 14.6 5.8
Currency transaction adjustments 8.1 13.4 (11.0) (7.4)
Gain on bargain purchase and measurement period adjustments - - (6.3) 637.0
Gain on extinguishment of debt - - 3.1 194.1
SHI settlement - - - 200.0
Settlement of legal dispute - - - (20.3)
Other income (expense) 0.1 1.1 3.8 (4.8)
$ 38.1 $ 25.9 $ 16.0 $ 1,006.2
Consolidated Statements of Cash Flows Information
Our restricted cash of $35.9 million at December 31, 2021 (Successor) consists primarily of $31.1 million of collateral on letters of credit. See "Note 15 - 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
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
(Increase) decrease in accounts receivable $ (18.3) $ 23.2 $ 53.3 $ 29.5
(Increase) decrease in other assets (48.4) 27.3 (63.8) (56.6)
Increase (decrease) in liabilities 77.0 18.0 (11.5) (25.4)
$ 10.3 $ 68.5 $ (22.0) $ (52.5)
Cash paid for interest and income taxes was as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Interest, net of amounts capitalized $ 22.8 $ - $ 190.0 $ 410.0
Income taxes 29.1 12.8 78.9 107.6
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 and $20.9 million during the years ended December 31, 2020 and 2019 (Predecessor), respectively.
Accruals for capital expenditures totaling $9.3 million and $6.5 million as of December 31, 2021 (Successor) and April 30, 2021 (Predecessor), respectively, were excluded from Investing activities in our Consolidated Statements of Cash Flows. Additionally, accruals for capital expenditures totaling $5.4 million and $16.3 million as of December 31, 2020 and 2019 (Predecessor), respectively, were excluded from Investing activities in our Consolidated Statements of Cash Flows.
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.
Concentration of Risk
We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents, and at times, investments. Previously, our use of derivatives in connection with the management of foreign currency exchange rate risk also subjected us to credit risk. 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. We mitigate our credit risk relating to cash and investments by focusing on diversification and quality of instruments.
We mitigated our credit risk relating to counterparties of our previous derivatives through a variety of techniques, including transacting with multiple, high-quality financial institutions, thereby limiting our exposure to individual counterparties and by entering into International Swaps and Derivatives Association, Inc. ("ISDA") Master Agreements, which included provisions for a legally enforceable master netting agreement, with our derivative counterparties. The terms of the ISDA agreements may also have included credit support requirements, cross default provisions, termination events or set-off provisions. Legally enforceable master netting agreements reduce credit risk by providing protection in bankruptcy in certain circumstances and generally permitting the closeout and netting of transactions with the same counterparty upon the occurrence of certain events. See "Note 10 - Derivative Instruments" for additional information on our previous derivative activity.
Consolidated revenues by customer were as follows:
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
BP (1)
11 % 14 % 11 % 9 %
Total(2)
9 % - % 8 % 16 %
Other 80 % 86 % 81 % 75 %
100 % 100 % 100 % 100 %
(1)During the eight months ended December 31, 2021(Successor), 21% of the revenues provided by BP were attributable to our Floaters segment, 20% of the revenues provided by BP were attributable to our Jackups segment and the remaining were attributable to our managed rigs.
During the four months ended April 30, 2021 (Predecessor), 37% of the revenues provided by BP were attributable to our Floaters segment, 17% of the revenues provided by BP were attributable to our Jackups segment and the remaining were attributable to our managed rigs.
For the year ended December 31, 2020 (Predecessor), 30% of the revenues provided by BP were attributable to our Floaters segment, 19% were attributable to our Jackups segment, and 51% of the revenues were attributable to our managed rigs.
For the year ended December 31, 2019 (Predecessor), 41% of the revenues provided by BP were attributable to our Jackups segment, 16% of the revenues were attributable to our Floaters segment and 43% of the revenues were attributable to our managed rigs.
(2)During the eight months ended December 31, 2021 (Successor), all of the revenues provided by Total were attributable to the Floaters segment.
For the years ended December 31, 2020 and 2019 (Predecessor), 71% and 93% of the revenues provided by Total were attributable to the Floaters segment and the remainder was attributable to the Jackup segment.
For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues by region were as follows (in millions):
Successor Predecessor
Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
United Kingdom(1)
$ 185.2 $ 75.7 $ 211.3 $ 213.1
Norway(1)
123.9 73.3 188.5 39.2
U.S. Gulf of Mexico(2)
109.9 74.4 241.4 301.0
Saudi Arabia(3)
92.3 53.6 200.8 313.4
Mexico(4)
77.8 44.3 112.1 73.0
Angola(5)
19.4 20.5 86.3 284.0
Other 226.5 55.6 386.8 829.5
$ 835.0 $ 397.4 $ 1,427.2 $ 2,053.2
(1)During the eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and for the years ended December 31, 2020 and 2019 (Predecessor) all revenues earned in the United Kingdom and Norway were attributable to our Jackups segment.
(2)During the eight months ended December 31, 2021 (Successor), 48% and 1% of the revenues earned in the U.S. Gulf of Mexico, were attributable to our Floaters segment and Jackups segment, respectively. The remaining revenues were attributable to our managed rigs. During the four months ended April 30, 2021 (Predecessor), 64% of the revenues earned in the U.S. Gulf of Mexico, were attributable to our Floaters segment. The remaining revenues were attributable to our managed rigs.
For the years ended December 31, 2020 and 2019 (Predecessor), 55% and 46% of the revenues earned in the U.S. Gulf of Mexico, respectively, were attributable to our Floaters segment, 11% and 28% of the revenues were attributable to our Jackups segment, for the respective periods, and the remaining revenues were attributable to our managed rigs.
(3)During the eight months ended December 31, 2021(Successor) and four months ended April 30, 2021 (Predecessor), 60% and 57% of the revenues earned in Saudi Arabia, respectively were attributable to our Jackups segment. The remaining revenues were attributable to our Other segment and relates to our rigs leased to ARO and certain revenues related to our Secondment Agreement.
For the years ended December 31, 2020 and 2019 (Predecessor), 63% and 65% of the revenues earned in Saudi Arabia, respectively, were attributable to our Jackups segment. The remaining revenues were attributable to our Other segment and related to our rigs leased to ARO and certain revenues related to our Secondment Agreement and Transition Services Agreement.
(4)During the eight months ended December 31, 2021 (Successor), 52% of the revenues earned in Mexico were attributable to our Jackups segment and the remaining revenues were attributable to our Floaters segment. During the four months ended April 30, 2021 (Predecessor), 51% of the revenues earned in Mexico were attributable to our Jackups segment and the remaining revenues were attributable to our Floaters segment.
For the year ended December 31, 2020 (Predecessor), 54% of the revenues earned in Mexico were attributable to our Floaters segment and the remaining revenues were attributable to our Jackups segment. For the year ended December 31, 2019 (Predecessor), all revenues earned in Mexico were attributable to our Floaters segment.
(5) During the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), all the revenues earned in Angola were attributable to our Floaters Segment.
For the years ended December 31, 2020 and 2019 (Predecessor), 84% and 87% of the revenues earned in Angola, respectively, were attributable to our Floaters segment and the remaining revenues were attributable to our Jackups segment.
19. RELATED PARTIES
See "Note 6 - 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 as of December 29, 2021 when his employer, Oakhill Advisors, was acquired by T. Rowe Price. T. Rowe Price provides administrative services for the Company's 401(k) Plan. As the employer matching contributions to the Company's 401(k) Plan were suspended during the Successor Period 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 or payables as of December 31, 2021.
Mr. Deepak Munganahalli is a director of the Company and is also the cofounder and a current employee of Joulon. 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, engineering services and high pressure equipment, inspection services, riser related services (including storage, inspection, preservation and repair), and rig stacking and maintenance arrangements. We incurred expense of $8.8 million during the eight months ended December 31, 2021 related to these goods and services and have a payable to them of $2.5 million as of December 31, 2021.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
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 Interim 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.
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.
Changes in Internal Controls - During the quarter ended December 31, 2021 there were no changes in our internal control over financial reporting 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.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Not applicable.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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, 2021 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.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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, 2021:
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)
1,467,438 - 7,493,135
Total 1,467,438 $ - 7,493,135
(1)Restricted share units and restricted shares 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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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 93
Consolidated Statements of Comprehensive Income 94
Consolidated Balance Sheets 95
Consolidated Statements of Cash Flows 96
Notes to Consolidated Financial Statements 97
2. Exhibits
Exhibit
Number
Exhibit
2.1 Fourth Amended Joint Chapter 11 Plan of Reorganization of Valaris plc and its Debtor Affiliates Pursuant to Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit A of Order Confirming the Debtor's Fourth Amended Joint Chapter 11 Plan of Reorganization, filed as Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on March 5, 2021, File No . 001-08097).
3.1 Memorandum of Association of Valaris Limited (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 18097).
3.2 Bye-laws of Valaris Limited (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
4.1 Indenture, dated as of April 30, 2021, among Valaris Limited, the guarantors listed therein, and Wilmington Savings Fund Society, FSB as collateral agent and trustee (including the form of First Lien Note attached thereto) (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
4.2 First Supplemental Indenture, dated as of July 6, 2021, among Valaris Limited, Alpha South Pacific Holding Company, and Wilmington Savings Fund, FSB as collateral agent and trustee (incorporated by reference to Exhibit 4.2 to the Company’s Amendment No. 9 to the Registration Statement on Form S-1 filed on July 7, 2021, File No. 333-257022).
4.4* Second Supplemental Indenture, dated as of January 12, 2022, among Valaris Limited, Valaris United LLC, and Wilmington Savings Fund, FSB as collateral agent and trustee.
4.5 Warrant Agreement, dated as of April 30, 2021, by and between Valaris Limited and Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
4.6* Description of the Company’s Common Shares.
4.7* Description of the Company’s Warrants.
10.1 Rowan Asset Transfer and Contribution Agreement, dated as of November 21, 2016, between Rowan Rex Limited and Saudi Aramco Development Company (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).
10.2 Amendment No. 1 to Rowan Asset Transfer and Contribution Agreement, dated as of October 17, 2017, by and between Saudi Aramco Development Company, Rowan Rex Limited and Saudi Aramco Rowan Offshore Drilling Company (incorporated by reference to Exhibit 2.1 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).
10.3 Shareholders’ Agreement dated 21 November 2016 (G) between Saudi Aramco Development Company and Rowan Rex Limited Relating to the Offshore Drilling Joint Venture (incorporated by reference to Exhibit 10.38 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).
10.4 Amendment No. 1 to the Shareholders' Agreement dated December 18, 2017 between Saudi Aramco Development Company, Rowan Rex Limited and ARO (incorporated by reference to Exhibit 10.17 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021).
10.5 Amendment No. 2 to the Shareholders' Agreement dated June 28, 2018 between Saudi Aramco Development Company, Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited (incorporated by reference to Exhibit 10.18 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021).
10.6 Amendment No. 3 to the Shareholders' Agreement dated August 13, 2020 between Rowan Rex Limited, Mukamala Oil Field Services Limited and ARO (incorporated by reference to Exhibit 10.19 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021)
10.7 Amendment No. 4 to the Shareholders' Agreement dated December 1, 2020 between Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited (incorporated by reference to Exhibit 10.20 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021)
+10.8 ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.9 Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.10 Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.11 Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.12 Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated December 22, 2009 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.13 Amendment No. 5 to the Ensco Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated May 14, 2012 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.14 Amendment No. 6 to the ENSCO Supplemental Executive Retirement Plan (as Amended and Restated Effective January 1, 2004), effective as of July 1, 2021, by ENSCO International Incorporated (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report filed on Form 10-Q on August 3, 2021, File No. 1-8097).
+10.15 ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.16 Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.17 Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097).
+10.18 Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated December 22, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.19 Amendment No. 4 to the Ensco 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.20 Amendment No. 5 to the Ensco 2005 Amended and Restated Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 21, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 24, 2013, File No. 1-8097).
+10.21 Amendment No. 6 to the ENSCO 2005 Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2005), dated December 19, 2019. (incorporated by reference to Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2019, File No. 1-8097).
+10.22 Amendment No. 7 to the ENSCO 2005 Supplemental Executive Retirement Plan (as Amended and Restated Effective January 1, 2005), effective as of July 1, 2021, by ENSCO International Incorporated (incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report filed on Form 10-Q on August 3, 2021, File No. 1-8097).
+10.23 ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).
+10.24 Restoration Plan of Rowan Companies, Inc. (as amended and restated effective January 1, 2013), incorporated by reference to Exhibit 10.7 to Rowan's Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-5491).
+10.25 Valaris Cash Incentive Plan (incorporated by reference to Exhibit 10.8 to the Registrant's Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097)
+10.26 Restructuring Support Agreement, dated August 18, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report filed on Form 8-K on August 19, 2020, File No. 1-8097).
+10.27 Backstop Commitment Agreement, dated August 18, 2020, by and among the company and the commitment parties named therein (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report filed on Form 8-K on August 19, 2020, File No. 1-8097).
+10.28 Amendment to Restructuring Support Agreement and Backstop Commitment Agreement dated as of September 10, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on September 11, 2020, File No. 1-8097).
+10.29 Second Amendment to Restructuring Support Agreement, by and among Valaris plc, its Affiliate Debtors and the noteholders party thereto, dated as of February 5, 2021 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on February 8, 2021, File No. 1-8097).
+10.30 Third Amendment to Backstop Commitment Agreement, by and among Valaris plc, its Affiliate Debtors and the Commitment Parties, dated as of February 5, 2021 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report filed on Form 8-K on February 8, 2021, File No. 1-8097).
+10.31 Settlement Agreement dated September 14, 2021, among ENSCO Global Resources Limited, Thomas Burke and Valaris Limited (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.32 Separation and Release Agreement, dated September 15, 2021, between Jonathan Baksht and Valaris (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.33 Interim CFO Letter Agreement, dated August 18, 2021, between Darin Gibbins and Valaris (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.34 Form of Valaris Limited 2021 Management Incentive Plan (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
+10.35 Form of PSU Award Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.36 Form of Deferred RSU Award Agreement (incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.37 Form of Director RSU Agreement (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097).
+10.38 Form of Change in Control Severance Agreement for Executive Officers (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q filed on April 28, 2016, File No. 1-8097).
10.39 Equity Registration Rights Agreement, dated as of April 30, 2021, by and among Valaris Limited and the holders party thereto (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
10.40 Notes Registration Rights Agreement, dated as of April 30, 2021, by and among Valaris Limited and the holders party thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
10.41 Support Agreement, dated as of December 9, 2021, among Valaris Limited, Famatown Financial Limited and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 10, 2021, File No. 1-8097).
+10.42 Executive Severance Plan of Valaris Limited (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097).
10.43* Employment Agreement, effective as of December 8, 2021, by and between Anton Dibowitz, Ensco Corporate Resources LLC and Valaris Limited.
10.44* Cash Retention Letter (Gilles Luca) effective as of August 18, 2021
10.45* Amendment to Cash Retention Letter (Gilles Luca) effective as of January 20, 2022.
*21.1 Subsidiaries of the Registrant.
*22.1 List of Guarantor Subsidiaries and Affiliate Securities Pledged as Collateral
*23.1 Consent of Independent Registered Public Accounting Firm.
*31.1 Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2 Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1 Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2 Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*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
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*101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
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*104 The cover page of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, 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.