Valaris Ltd 10-K

val-20201231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 , 2020 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 1-8097 Valaris plc (Exact name of registrant as specified in its charter) England and Wales 98-0635229 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) Cannon Place, 78 Cannon Street London, England EC4N 6AF (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: +44 (0) 20 7659 4660 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Title of each class Ticker Symbol(s) Name of each exchange on which registered Class A ordinary shares, U.S. $0.40 par value VALPQ OTC Pink Open Market Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act: Large accelerated filer o Accelerated filer ☒ Non-Accelerated filer o Smaller reporting company ☒ Emerging growth company ☐ ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ The aggregate market value of the Class A ordinary shares (based upon the closing price on the New York Stock Exchange on June 30, 2020 of $0.65 of Valaris plc held by non-affiliates of Valaris plc at that date) was approximately $ 104,731,000 . As of February 22, 2021, there were 199,613,642 Class A ordinary shares of Valaris plc issued and outstanding. TABLE OF CONTENTS PART I ITEM 1. BUSINESS 6 ITEM 1A. RISK FACTORS 18 ITEM 1B. UNRESOLVED STAFF COMMENTS 50 ITEM 2. PROPERTIES 51 ITEM 3. LEGAL PROCEEDINGS 54 ITEM 4. MINE SAFETY DISCLOSURES 55 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 56 ITEM 6. SELECTED FINANCIAL DATA 61 ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 61 ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 100 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 101 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 180 ITEM 9A. CONTROLS AND PROCEDURES 180 ITEM 9B. OTHER INFORMATION 180 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 181 ITEM 11. EXECUTIVE COMPENSATION 186 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS 197 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 199 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 200 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 201 ITEM 16. FORM 10-K SUMMARY 210 SIGNATURES 211 FORWARD-LOOKING STATEMENTS Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "likely," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; the outcome and effects of the Chapter 11 Cases (as defined below); expected utilization, day rates, revenues, operating expenses, cash flows, contract terms, contract backlog, capital expenditures, insurance, financing and funding; the effect, impact, potential duration and other implications of the COVID-19 pandemic; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effects of declines in commodity prices; expected work commitments, awards and contracts; the timing of availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; future rig construction (including work in progress and completion thereof), enhancement, upgrade or repair and timing and cost thereof; the suitability of rigs for future contracts; performance of our joint venture with Saudi Arabian Oil Company ("Saudi Aramco"); expected divestitures of assets; general market, business and industry conditions, trends and outlook; future operations; the impact of increasing regulatory complexity; the outcome of tax disputes, assessments and settlements; synergies and expected additional cost savings; dividends; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims or contract disputes and the timing thereof. Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, particularly in light of difficult market conditions, our projected negative cash flows in 2021 and highly leveraged balance sheet, including: • potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations; • objections to the confirmation of our plan of reorganization or other pleadings we file that could protract the Chapter 11 Cases; • our ability to comply with the restrictions and other covenants imposed by our DIP Credit Agreement (as defined herein) and other financial arrangements; • the Bankruptcy Court’s rulings in the Chapter 11 Cases, and the outcome of the Chapter 11 Cases generally; • the length of time that we will operate under chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings; • the COVID-19 pandemic, the related public health measures implemented by governments worldwide and the effects of the decline in oil prices during 2020, including the duration and severity of the outbreak, the duration of the price and demand decline and the extent of disruptions to our operations; • downtime or temporary shut down of operations of our rigs as a result of an outbreak of COVID-19 on one or more of our rigs; • disruptions to the operations and business, as a result of the spread of COVID-19, of our key customers, suppliers and other counterparties; • disputes over production levels among members of the Organization of Petroleum Exporting Countries and other oil and gas producing nations (“OPEC+”); 2 • decreases in levels of drilling activity and capital expenditures by our customers, whether as a result of the global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs; • delays in contract commencement dates or cancellation, suspension, renegotiation or termination (with or without cause, including due to impacts of the COVID-19 pandemic) of drilling contracts or drilling programs as a result of general and industry-specific economic conditions, mechanical difficulties, performance or other reasons; • potential additional asset impairments; • the adequacy of sources of liquidity for us and our customers; • the reaction of our customers, prospective customers, suppliers and service providers to the Chapter 11 Cases and the related increased performance and credit risks associated with our constrained liquidity position and capital structure; • our customers, in response to reduced oil price expectations, cancelling or shortening the duration of our drilling contracts, cancelling future drilling programs and seeking pricing and other contract concessions from us; • the impact of the delisting of our Class A ordinary shares from the New York Stock Exchange ("NYSE") in September 2020; • our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, unionization, or otherwise, or to retain employees as a result of the imposition of further public health measures due to the COVID-19 pandemic, our financial condition generally or as a result of the Chapter 11 Cases; • internal control risk due to significant employee reductions; • our ability to successfully integrate the business, operations and employees of Rowan Companies Limited (formerly Rowan Companies plc) ("Rowan") and the Company to realize synergies and cost savings in connection with the Company's 2019 combination with Rowan (the "Rowan Transaction"); • changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs and governmental policies that could reduce demand for hydrocarbons, including mandating or incentivizing the conversion from internal combustion engine powered vehicles to electric-powered vehicles; • downtime and other risks associated with offshore rig operations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris; • governmental action, terrorism, piracy, military action and political and economic uncertainties, including civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East, North Africa, West Africa or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation or 3 destruction of our assets; or suspension and/or termination of contracts based on force majeure events or adverse environmental safety events; • risks inherent to shipyard rig construction, repair, modification or upgrades, unexpected delays in equipment delivery, engineering, design or commissioning issues following delivery, or changes in the commencement, completion or service dates; • our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild rigs and acquired rigs, for rigs currently idled and for rigs whose contracts are expiring; • any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments; • the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, any renegotiation, nullification, cancellation or breach of contracts with customers or other parties; • governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season) and regulatory measures to limit or reduce greenhouse gases (such as the current moratorium on oil and gas leasing and permitting in federal lands and waters); • potential impacts on our business resulting from climate-change or greenhouse gas legislation or regulations, and the impact on our business from climate-change related physical changes or changes in weather patterns; • new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts, operations or financial results; • environmental or other liabilities, risks, damages or losses, whether related to storms, hurricanes or other weather-related events (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable; • tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes; • our ability to realize the expected benefits of our joint venture with Saudi Aramco, including our ability to fund any required capital contributions or to enforce any payment obligations of the joint venture pursuant to outstanding shareholder notes receivable; • activism by our security holders; • economic volatility and political, legal and tax uncertainties following the U.K.'s exit from the European Union; • the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems, including our rig operating systems; and 4 • adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of any derivative instruments that we may enter into. In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law. 5 PART I Item 1. Business General Valaris plc is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Valaris," "Company," "we," "us" and "our" refer to Valaris plc 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 61 rigs, with drilling operations in almost every major offshore market across five continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 45 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 nine countries on five continents. 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. Following several years of market volatility beginning with oil price declines in 2014, as we entered 2020, we expected that volatility 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 for the near term, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers to cancel or shorten the duration of many of our 2020 drilling contracts, cancel future drilling programs and seek pricing and other contract concessions which led to material operating losses and liquidity constraints for us. While there has been some recent improvement to Brent crude oil prices, to approximately $65 per barrel in February 2021, there is still a significant amount of uncertainty around the sustainability of the improvement in oil prices to support a recovery in demand for offshore drilling services. Additionally, the full impact that the pandemic and the decline in 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 outbreak, the effectiveness of the ongoing vaccine rollout, the duration of the oil price and 6 demand decline, and the extent of disruptions to our operations. To date, the COVID-19 pandemic has resulted in only 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. We expect that these challenges will continue for drilling contractors as customers wait to gain additional clarity on commodity pricing and seek to reduce costs in the near-term by attempting to renegotiate existing contract terms. We believe the current market and macro-economic conditions will create a challenging contracting environment through 2021 and into 2022 and potentially beyond. 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 have resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions. These recent events have 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). While we have and are continuing to pursue a variety of cost-cutting measures such as further reductions in corporate overhead and discretionary expenditures, reductions in capital expenditures and an increased focus on operational efficiencies, we determined that based on our significant level of indebtedness and the circumstances described above that a comprehensive restructuring of our indebtedness was needed to improve our financial position. As more fully described in “ Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data", the Company will undergo a financial restructuring that is intended to reduce debt levels substantially, support continued operations during the current lower demand environment and provide a robust financial platform to take advantage of market recovery over the long-term. Chapter 11 Proceedings and Ability to Continue as a Going Concern On August 19, 2020 (the “Petition Date”), Valaris plc 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”). As part of the chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”), the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption. On August 18, 2020, the Debtors entered into the Restructuring Support Agreement (the "Original RSA") with certain senior note holders (collectively, the "Consenting Noteholders"). On February 5, 2021, the Debtors entered into the Amended Restructuring Support Agreement (the “Amended RSA”) with the Consenting Noteholders and certain revolving credit facility lenders (the “Consenting Lenders” and, together with the Consenting Noteholders, the “Consenting Creditors”), which contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. Holders of approximately 100% of the total commitments outstanding under our revolving credit facility and holders of approximately 72% of the aggregate amount of our Senior Notes outstanding are party to the Amended RSA. 7 See “ Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional details regarding the Chapter 11 Cases and related items, the Amended RSA and our ability to continue as a going concern. 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 under the Rig Lease Agreements, the Secondment Agreement and the Transition Services Agreement. Floaters, Jackups and ARO are also reportable segments. We own and operate 61 rigs, 27 are located in the Middle East, Africa and Asia Pacific, 11 are located in North and South America and 23 are located in Europe as of December 31, 2020. 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 or (3) at the convenience (without cause) of the customer (in certain cases obligating the customer to pay us an early termination fee providing some level of compensation to us for the remaining term), • 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 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 8 • 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, following the downturn in offshore drilling demand commencing in 2014, contract awards have been subject to an extremely competitive bidding process. The intense pressure on operating day rates has resulted 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 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. Contract backlog is adjusted for drilling contracts signed or terminated after each respective balance sheet date but prior to filing each of our annual reports on Form 10-K on March 2, 2021 and February 21, 2020, respectively. Our backlog excludes ARO's backlog, but includes backlog from our rigs leased to ARO at the contractual rates, which are subject to adjustment by the shareholder agreement. See " Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. The following table summarizes our contract backlog of business as of December 31, 2020 and 2019 (in millions): 2020 2019 Floaters $ 205.7 $ 847.3 Jackups 859.5 1,281.2 Other (1) 140.1 324.3 Total $ 1,205.3 $ 2,452.8 (1) Other includes the bareboat charter backlog for the nine 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. As of December 31, 2020, our backlog was $1.2 billion as compared to $2.5 billion as of December 31, 2019. Our floater backlog declined $641.6 million and our jackup backlog declined $421.7 million. Changes resulted from revenues realized during the period, contract terminations and contract suspensions, partially offset by new contract awards and contract extensions. Our other segment backlog declined $184.2 million due to contract concessions and revenues realized during the period. 9 The following table summarizes our contract backlog of business as of December 31, 2020 and the periods in which such revenues are expected to be realized (in millions): 2021 2022 2023 2024 and Beyond Total Floaters $ 205.7 $ — $ — $ — $ 205.7 Jackups 548.7 235.8 75.0 — 859.5 Other (1) 130.2 9.9 — — 140.1 Total $ 884.6 $ 245.7 $ 75.0 $ — $ 1,205.3 (1) Includes the bareboat charter backlog for the nine 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. 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 some 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. 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. 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.” 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 personal injuries, damage to or loss of property and certain business risks. Our insurance policies typically consist of 12-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2021. 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 claims arising from our operations, including third-party claims arising from well-control events, named windstorms, sudden and accidental pollution originating from our rigs, wrongful death and personal injury. Third-party pollution claims could also arise from damage to adjacent pipelines and from spills of fluids maintained on the drilling rig. Generally, our program provides liability coverage up to $750.0 million, with a per occurrence deductible of $10.0 million or less. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage. Well-control events generally include an unintended release from a well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production facilities. In addition to the third-party coverage described above, for claims relating to a 10 well-control event, we also have $150.0 million of coverage available to pay costs of controlling and re-drilling of the well and third-party pollution claims. Our insurance program also provides coverage to us for physical damage (including total loss) to our rigs, excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig and has a per occurrence deductible for losses ranging from $15.0 million to $25.0 million. Due to the significant premium, high deductible and limited coverage, we do not purchase windstorm insurance for our rigs in the U.S. Gulf of Mexico. Accordingly, we retain the risk for windstorm damage to our jackup and floater rigs in the U.S. Gulf of Mexico. 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 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 11 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 that are assessed directly against such party on the ground that it is against public policy to indemnify a party from a fine and penalty or punitive damages, especially where the purpose of such levy or assessment is to deter the behavior that resulted in the fine 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 2020, our five largest customers accounted for 41% of consolidated revenues. BP, our only customer who accounts for 10% or more of consolidated revenues, accounted for 11% 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 12 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, 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 13 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. In late 2014, the United States Coast Guard ("USCG") proposed new regulations that would impose GPS equipment and positioning requirements for drilling rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of guidelines for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the Maritime Transportation Security Act of 2002 ("MTSA"), including our rigs. The regulations imposing GPS equipment and positioning requirements have not yet been issued. In March 2020, the USCG issued its “Guidelines for Addressing Cyber Risks at MTSA Regulated Facilities” in order to assist facility owners and operators in complying with the requirements to assess, document, and address computer system or network vulnerabilities. The MTSA regulations provide general requirements for regulated facility cybersecurity while allowing facility owners and operators the discretion to determine the details of how they will comply. Facility owners and operators are responsible for assessing and documenting cybersecurity vulnerabilities and ensuring cybersecurity of their facilities under the Coast Guard’s oversight and guidance. The Company is currently evaluating the new USCG guidelines and the extent to which the BSEE or other regulators will review our ability to address cybersecurity risks at MTSA-regulated facilities. As the USCG provides further detail on how these guidelines will be implemented, we will address our cybersecurity program to comply with any regulations that are ultimately promulgated. On July 28, 2016, BSEE adopted a new well-control rule that will be implemented in phases over the next several years (the "2016 Well Control Rule"). This new rule includes 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 new 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 14 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 current Presidential Administration officially reentered the United States into the agreement in February 2021. 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, 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. 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 83%, 85% and 87% of our total consolidated revenues during 2020, 2019 and 2018, 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, 15 • 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 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 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. See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations." 16 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, 2021: Name Age Position Thomas Burke 53 President and Chief Executive Officer Jonathan Baksht 46 Executive Vice President and Chief Financial Officer Gilles Luca 49 Senior Vice President - Chief Operating Officer Alan Quintero 57 Senior Vice President - Business Development Michael T. McGuinty 58 Senior Vice President - General Counsel and Secretary 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: Thomas Burke became the President and Chief Executive Officer of Valaris and a member of the Board of Directors in April 2019 in connection with the Rowan Transaction. Previously, he served as Rowan’s President and Chief Executive Officer as well as a director since April 2014. He served as Rowan’s Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Mr. Burke first joined Rowan in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Mr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development. Mr. Burke received his PhD in Engineering from Trinity College at the University of Oxford, a Bachelor of Science in Engineering with Honors from Heriot-Watt University in Scotland, and an MBA from Harvard Business School, where he was awarded a Baker Scholarship. Jonathan Baksht became Executive Vice President and Chief Financial Officer of Valaris in June 2019. Previously, he served as the Company's Senior Vice President - Chief Financial Officer since November 2015, and as Vice President - Finance and Vice President - Treasurer before his appointment as Chief Financial Officer. Prior to joining Valaris in August 2013, Mr. Baksht served as a Senior Vice President at Goldman Sachs & Co. within the Investment Banking Division where he served as a financial advisor to energy clients, oilfield services lead and a member of the Merger & Acquisitions Group. Prior to joining Goldman Sachs in 2006, he consulted on strategic initiatives for energy clients at Andersen Consulting. Mr. Baksht holds a Master of Business Administration from the Kellogg School of Management at Northwestern University and a Bachelor of Science with High Honors in Electrical Engineering from the University of Texas at Austin. 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. Alan Quintero became Senior Vice President - Business Development of Valaris in April 2019 in connection with the Rowan Transaction. Previously, he served as Rowan’s Senior Vice President, Business Development since 2018, after joining Rowan as Senior Vice President, Chief Technology Officer in 2017. Prior to joining Rowan, Mr. Quintero was a Partner at Trenegy Incorporated, a management consulting firm, from January 2016 to June 2017, and spent more than 20 years in various operational and managerial roles for international offshore drilling companies including serving as Senior Vice President, Operations at Transocean. Mr. Quintero received a Bachelor of Science in Mechanical Engineering from Texas A&M University. He also received education at Heriot-Watt University, Columbia University, Harvard University and the Wharton School of Business. Michael T. McGuinty joined Valaris in February 2016 as Senior Vice President - General Counsel and Secretary. Prior to joining Valaris, Mr. McGuinty served as General Counsel and Company Secretary of Abu Dhabi 17 National Energy Company from January 2014 to December 2015. Previously, Mr. McGuinty spent 18 years with Schlumberger where he held various senior legal management positions in the United States, Europe and the Middle East including Director of Compliance, Deputy General Counsel - Corporate and M&A and Director of Legal Operations. Prior to Schlumberger, Mr. McGuinty practiced corporate and commercial law in Canada and France. Mr. McGuinty holds a Bachelor of Laws and Bachelor of Civil Law from McGill University and a Bachelor of Social Sciences from the University of Ottawa. Employees We employed approximately 4,500 personnel worldwide including contract employees, and approximately 3,400 personnel excluding contract employees, as of December 31, 2020. 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 Chapter 11 Proceedings • Operating under the Bankruptcy Court protection for a long period of time may harm our business. • We may not be able to obtain confirmation of a plan of reorganization. • We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation. • As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends. • We may be subject to claims that will not be discharged in the Chapter 11 Cases. • Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court. • The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, and we may face increased levels of employee attrition. • Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. • In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code. • Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution. • We may not be able to achieve our stated goals and continue as a going concern under a plan of reorganization. 18 • Our ability to use our net operating loss carryforwards ("NOLs") may be limited by changes in ownership due to the Chapter 11 Cases. Risks Related to Our Business, Operations and Market Conditions • The COVID-19 pandemic and recent developments in the oil and gas industry could 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 volatile 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 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. • We have a significant amount of debt. Our debt levels and debt agreement restrictions may limit our liquidity, our ability to obtain additional financing and our pursuit of other business opportunities. • 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. • We may incur impairments as a result of future declines in demand for offshore drilling rigs. • The loss of a significant customer or customer contract could adversely affect us. • Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future . • We may not realize the expected benefits of the ARO joint venture, 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. • We have taken, and continue to take, cost-reduction actions, which may not be successful. • We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not protect us against all of the risks and hazards we face, including those specific to offshore operations. • 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. • Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers. • 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. • Rig construction, upgrade, enhancement and reactivation 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. • Failure to recruit and retain skilled personnel could adversely affect our business. • We have historically made significant capital 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. • Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility. • 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. • Our long-term contracts are subject to the risk of cost increases, which could adversely affect our profitability. • Our information technology systems, including rig operating systems, are subject to cybersecurity risks and threats. 19 Risks Related to Our Indebtedness and Ordinary Shares • Our Class A ordinary shares have been delisted from the NYSE. • The accounting method for our 2024 Convertible Notes could have a material effect on our reported financial results. • Transfers of our Class A ordinary shares may be subject to stamp duty or stamp duty reserve tax ("SDRT") in the U.K., which would increase the cost of dealing in our Class A ordinary shares. • If our Class A ordinary shares are not eligible for continued deposit and clearing within the facilities of DTC, then transactions in our securities may be disrupted. • We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements. • Our articles of association contain anti-takeover provisions; however, the Company is not subject to the U.K.'s City Code on Takeovers and Mergers. • English law requires that we meet certain additional financial requirements before declaring dividends and returning funds to shareholders. Legal, Regulatory and Tax Risks • Failure to comply with anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act, could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business. • Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations and reduce demand. • Compliance with or breach of environmental laws can be costly and could limit our operations. • Regulation of greenhouse gases and climate change could have a negative impact on our business. • The 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 acquisition strategies and certain internal restructurings. • 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. • Investor enforcement of civil judgments against us may be more difficult. • 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. • The U.K.'s withdrawal from the E.U. may have a negative effect on economic conditions, financial markets and our business. Item 1A. Risk Factors Risks Related to Chapter 11 Proceedings We are subject to the risks and uncertainties associated with the Chapter 11 Cases. On August 19, 2020, the Debtors filed the Chapter 11 Cases in the United States Bankruptcy Court for the Southern District of Texas. For the duration of the Chapter 11 Cases, our operations and our ability to develop and execute the business plan, as well as our continuation as a going concern, are subject to risks and uncertainties associated with bankruptcy. These risks include the following: • our ability to execute, confirm and consummate a plan of reorganization as contemplated by the Amended RSA with respect to the Chapter 11 Cases; • the high costs of bankruptcy proceedings and related fees; 20 • our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence; • our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties; • our ability to maintain contracts that are critical to our operations; • our ability to execute our business plan in the current depressed commodity price environment; • our ability to attract, motivate and retain key employees; • the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us; • the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to a chapter 7 proceeding; and • the actions and decisions of our creditors and other third parties who have interests in the Chapter 11 Cases that may be inconsistent with our plans. Delays in the Chapter 11 Cases increase the risks of us being unable to reorganize our business and emerge from bankruptcy, and also increase our costs associated with the bankruptcy process. These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with customers, suppliers, service providers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond in a timely fashion to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of a plan of reorganization as contemplated by the Amended RSA. Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during or as a result of the Chapter 11 Cases will have on our business, financial condition, results of operations and cash flows. Even if a plan of reorganization is consummated, we will continue to face a number of risks, including those associated with our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence of our customers, suppliers, service providers, employees and other third parties. Accordingly, we cannot guarantee that the proposed financial restructuring will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern. Operating under the Bankruptcy Court protection for a long period of time may harm our business. A long period of operations under the protection of the Bankruptcy Court could have a material adverse effect on our business, financial condition, results of operations and liquidity. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships. So long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. Furthermore, we cannot predict the ultimate terms of settlement of the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from chapter 11 bankruptcy. We may not be able to obtain confirmation of a plan of reorganization. To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a chapter 11 plan of reorganization, solicit and 21 obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if a plan of reorganization as contemplated by the Amended RSA meets other requirements under the Bankruptcy Code, certain interested parties may file objections to the plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our plan are received from creditors entitled to vote on the plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the plan of reorganization. The precise requirements and evidentiary requirements for having a plan confirmed, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims). If a plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims. We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation. Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As of December 31, 2020, our total available liquidity was $825.8 million, which included $325.8 million of cash on hand and $500.0 million available under our DIP Facility. We expect to continue using cash on hand that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the DIP Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of a plan of reorganization. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, that such funds will be offered to us on acceptable terms. As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends. During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if we emerge from chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to our operating plans pursuant to a plan of reorganization. We anticipate that we will adopt fresh start accounting upon our emergence from chapter 11, becoming a new entity for financial reporting purposes. As a result, upon emergence, the Company’s assets and liabilities will generally be reported at fair value and will reconcile to the enterprise value confirmed by the Bankruptcy Court. These fair values are expected to differ materially from the amounts reflected on our historical balance sheet. We may be subject to claims that will not be discharged in the Chapter 11 Cases. The Bankruptcy Code provides that the confirmation of a plan of reorganization may discharge a debtor from substantially all debts arising prior to the Petition Date. Although the Company intends to pay pre-petition trade claims in full, with few exceptions, all claims that arose before the Petition Date (1) are subject to compromise and/or treatment under a plan of reorganization and/or (2) could be discharged in accordance with the terms of a plan of reorganization. The Bankruptcy Code excepts certain pre-petition claims from discharge for corporate debtors, including certain debts owed to governmental entities obtained by, among other things, false 22 representations or actual fraud. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis. Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court. In connection with the plan of reorganization process, we were required to prepare projected financial information to demonstrate to the Bankruptcy Court the feasibility of the restructuring plan and our ability to continue operations upon emergence from bankruptcy. At the time they were last filed with the Bankruptcy Court on December 30, 2020, the projections reflected numerous assumptions concerning anticipated future performance and prevailing and anticipated market and economic conditions that were and continue to be beyond our control and that may not materialize. Further, to the extent we issue new guidance, such projections will supersede any prior guidance. Projections, in any event, are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks. Our actual results will vary from those contemplated by our projections and the variations may be material. The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition. While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Cases instead of focusing exclusively on our business operations. This diversion of attention may have a material adverse effect on the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted. During the duration of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations. Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. It is possible that our Class A ordinary shares will be cancelled pursuant to the plan of reorganization and holders of any such ordinary shares will receive only such distributions as set forth in the plan of reorganization, which may result in such holders being unable to recover their investments. A significant amount of our indebtedness is senior to the Class A ordinary shares in our capital structure. It is unclear at this stage of the Chapter 11 Cases if any plan of reorganization would allow for distributions with respect to our Class A ordinary shares and other outstanding equity interests without the consent of the senior debt holders. It is possible that these equity interests may be cancelled and extinguished upon the approval of the Bankruptcy Court and the holders thereof would not be entitled to receive, and would not receive or retain, any property or interest in property on account of such equity interests. In the event of a cancellation of these equity interests, amounts invested by such holders in our outstanding equity securities will not be recoverable. Under the current plan of reorganization, holders of our Class A ordinary shares may be entitled to receive their pro rata share of 7-year warrants to purchase up to 7% of New Equity (subject to dilution). However, if our plan of reorganization is not approved, our currently outstanding Class A ordinary shares may have no value. Trading prices for our Class A ordinary shares are very volatile and may bear little or no relationship to the actual recovery, if any, by the holders of such securities in the Chapter 11 Cases. Accordingly, we urge that extreme caution be exercised with respect to existing and future investments in our equity securities and any of our other securities. In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code. Upon a showing of cause, the Bankruptcy Court may convert the Chapter 11 Cases to cases under chapter 7 23 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (1) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (2) additional administrative expenses involved in the appointment of a chapter 7 trustee, and (3) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations. Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution. Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (1) our ability to substantially change our capital structure, (2) our ability to obtain adequate liquidity and financing sources, (3) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (4) our ability to retain key employees and (5) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization. We may not be able to achieve our stated goals and continue as a going concern under a plan of reorganization. Even if a plan of reorganization is consummated, we will continue to face a number of risks. For example, improvements in demand for offshore drilling services and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized. Accordingly, we cannot guarantee that a plan of reorganization will achieve our stated goals. Furthermore, even if our debts are reduced or discharged through such plan, we may need to raise additional funds through public or private debt or equity financing or other means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all. Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a chapter 11 plan of reorganization is confirmed. Our ability to use our NOL carryforwards may be limited by changes in ownership due to the Chapter 11 Cases. As of December 31, 2020, we had deferred tax assets of $2.3 billion relating to $9.7 billion of NOL carryforwards, $171.2 million for U.S. foreign tax credits (“FTCs”) and $221.2 million for U.S. and U.K. interest limitation carryforwards, which can be used to reduce our income taxes payable in future years. NOL 24 carryforwards, which were generated in various jurisdictions worldwide, include $9.5 billion that do not expire and $223.0 million that will expire, if not utilized, between 2021 and 2040. Deferred tax assets for NOL carryforwards at December 31, 2020 include $1.4 billion and $687.3 million pertaining to NOL carryforwards in Luxembourg and the United States, respectively. The U.S. FTCs expire between 2021 and 2028. The interest limitation carryforwards do not expire. Due to the uncertainty of realization, we have a $2.7 billion valuation allowance on deferred taxes relating to NOL carryforwards, U.S. FTCs and interest limitation carryforwards. Under Section 382 of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. NOL carryforwards, FTCs and interest limitation carryforwards that can be utilized annually in the future to offset U.S. taxable income. Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given relative to our ability to utilize our U.S. NOL carryforwards, FTCs and interest limitation carryforwards in the future. If we are limited in our ability to use our U.S. NOL carryforwards, FTCs and interest limitation carryforwards in future years in which we have taxable income, we will pay more taxes than if we were able to utilize them fully. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our U.S. NOL carryforwards, FTCs and interest limitation carryforwards. Risks Related to Our Business, Operations and Market Conditions The COVID-19 pandemic and recent developments in the oil and gas industry has, and could continue to, adversely impact our financial condition and results of operations. The COVID-19 pandemic and related public health measures implemented by governments worldwide have negatively impacted the global macroeconomic environment and resulted in a sharp decline in global oil demand and prices. As of February 2021, crude oil prices have recovered from the historic lows seen in the first half of 2020 and have returned to 2019 prices. However, our customers have generally lowered their capital expenditure plans, in many cases significantly, in light of revised pricing expectations. To date, there have been various impacts from the pandemic and the resultant drop in oil prices, including contract cancellations and the 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 coronavirus 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. Oil prices are expected to continue to be volatile as a result of the near-term production instability, ongoing COVID-19 outbreaks, the implementation of vaccination programs and the related impact on overall economic activity, 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 the oil and gas industry, 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 drilling activity and operator capital spending decline, 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 will be exacerbated by the entry of newbuild rigs into the market. Oil and natural gas prices have historically been volatile, and have 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. Brent crude averaged nearly $42 per barrel in 2020 with a year-end price of $51. Commodity prices in 2021 have not improved to a level that supports increased rig demand sufficient to absorb existing rig supply and generate meaningful increases in day rates. We expect these trends to continue as long as commodity prices and rig supply remain at current levels. The lack of a meaningful recovery of oil and natural gas prices or further price reductions or volatility in prices may cause our customers to maintain historically low capital spending levels or further reduce their overall level of activity, in 25 which case demand for our services may further decline and revenues may continue to 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 and any government response to such occurrence or threat, • oil and natural gas supply and demand, • 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 onshore 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, • 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), • 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 of the Middle East or geographic areas in which we operate, or acts of terrorism. Despite significant declines in capital spending and cancelled or deferred drilling programs by many operators since 2014, oil and gas production has not yet been reduced by amounts sufficient to result in a rebound in pricing to levels seen in 2014, and we may not see sufficient supply reductions or a resulting rebound in pricing for an extended period of time. Further, 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 26 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, 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 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. These factors could cause our revenues and profits to decline further, 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 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 job. 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 be reduced. The offshore contract drilling industry historically has been very cyclical and is primarily related to the demand for drilling rigs and the available supply of drilling rigs. Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region. The significant decline in oil and gas prices and resulting reduction in spending by our customers, together with the increase in supply of offshore drilling rigs in recent years, has resulted in an oversupply of offshore drilling rigs and a decline in utilization and day rates, a situation which may persist for many years. Such a prolonged period of reduced demand and/or excess rig supply has 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. Any further decline in demand for drilling rigs or a continued oversupply of drilling rigs could adversely affect 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 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. In addition, if customers do not exercise option periods under contracts that we currently expect to be exercised, we may face longer downtime associated with the related rig, as we would have difficulty tendering that rig for additional work to cover the option period. 27 On December 30, 2020, we reached an agreement in principle to amend and assume pursuant to section 365 of the Bankruptcy Code two agreements for the construction of two new rigs, which was subsequently modified through further negotiations. On February 26, 2021, we entered into amended agreements that extend the delivery date for both new rigs to December 31, 2023. The two rigs under construction are currently uncontracted. There is no assurance that we will secure drilling contracts for these rigs, or future rigs we construct or acquire, or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contracts for these rigs at day rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results or cash flows. We have a significant amount of debt. Our debt levels and debt agreement restrictions may limit our liquidity, our ability to obtain additional financing our pursuit of other business opportunities. As of December 31, 2020, we had $7.1 billion in total debt outstanding, representing approximately 61.9% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including: • a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest, and • our ability to access capital markets, refinance our existing indebtedness, raise capital on favorable terms, or obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, debt service requirements, execution of our business strategy and general corporate or other cash requirements may be limited. Our ability to maintain a sufficient level of liquidity to meet our financial obligations will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. For 2020 and 2019, our cash flows from operating activities of continuing operations were negative $251.7 million and $276.9 million, respectively, and we further incurred capital expenditures on continuing operations of $93.8 million and $227.0 million, respectively. Our operating activities and capital expenditures are expected to continue to result in negative annual cash flow in 2021. Meaningful recovery in drilling demand and day rates are required for annual cash flow to turn positive. To the extent we are unable to repay our debt and other obligations as they become due with cash on hand or from other sources, we will need to restructure or refinance all or part of our debt, sell assets, reduce capital expenditures, borrow more cash or raise equity. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing debt and other obligations, or if available, such additional debt or equity financing may not be available in a sufficient amount, on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell additional assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale. Our revolving credit facility places restrictions on us and certain of our subsidiaries with respect to incurring additional indebtedness and liens, paying dividends and other payments to shareholders, repurchasing our ordinary shares, repurchasing or redeeming certain other indebtedness which matures after the revolving credit facility, entering into mergers and other matters. Our revolving credit facility also requires compliance with covenants to maintain specified financial and guarantee coverage ratios, including a total debt to total capitalization ratio that is less than or equal to 60%. As of December 31, 2020, our total debt to total capitalization ratio was 61.9%. As of August 19, 2020, we have been in default under certain of our debt instruments. Our filing of the Chapter 11 Cases accelerated our obligations under the Senior Notes (as defined below). Additionally, events of 28 default under the indentures governing our Senior Notes have occurred and are continuing, including as a result of cross-defaults between such indentures. 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, including with respect to well-control, reservoir liability and pollution. 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 any 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 similar to the current environment, 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 in light of depressed market conditions. Since early 2015, we have renegotiated a number of contracts and received termination notices with respect to several of our rigs. Often, our drilling contracts are 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 a termination for convenience (without cause). 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 of our contracts 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. During 2020, the offshore drilling market suffered serious negative effects in relation to the COVID-19 pandemic and a significant drop in oil and gas commodity prices. Global economic shutdowns driven by COVID-19 served to exacerbate the reduction in world demand for oil and gas which then prompted operators to slash budgets and defer, cancel and/or renegotiate rates for existing contracts. 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. 29 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. 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 we have recorded pre-tax, non-cash losses on impairment of long-lived assets totaling $9.0 billion, including $3.6 billion aggregate pre-tax, non-cash impairments with respect to certain floaters, jackups and spare equipment, which we recorded during the first and second quarters of 2020. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. See " N ote 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. The loss of a significant customer or customer contract could adversely affect us. We provide our services to major international, government-owned and independent oil and gas companies. During 2020, our five largest customers accounted for 41% of our consolidated revenues in the aggregate, with our largest customer representing 11% of our consolidated revenues and a significant percentage of our operating cash flows. Our ability to retain existing significant customers may be adversely affected by the ongoing Chapter 11 Cases and certain of our largest customers have discussed with us our financial viability to perform for the duration of the potential terms of new contracts. 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. Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future. As of December 31, 2020, our contract backlog was approximately $1.2 billion, which represents a decline of $1.2 billion to the reported backlog of $2.5 billion as of December 31, 2019. 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, 30 • 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. 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. The decline in oil prices and the resulting downward pressure on utilization has caused and may continue to cause some customers to consider early termination of select contracts despite having to pay onerous early termination fees in certain cases. Customers may continue to request to renegotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts in some circumstances. Furthermore, as our existing contracts expire, we may be unable to secure new contracts for our 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. We may not realize the expected benefits of the ARO joint venture, 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. In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each selling existing drilling rigs and contributing capital as the foundation of the new company. The new entity, Saudi Aramco Rowan Offshore Drilling Company (ARO) commenced operations on October 17, 2017, and is expected to add up to 20 newbuild jackup rigs to its fleet over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups for delivery scheduled 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 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 issued 10-year shareholder notes receivables to ARO, which are governed by the laws of Saudi Arabia, earn interest at LIBOR plus two percent and 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 notes receivable may be reduced by future Company obligations to the joint venture. 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. 31 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. We have taken, and continue to take, cost-reduction actions, which may not be successful. After announcing significant synergy targets and cost savings in connection with the Rowan Transaction, we are implementing these and additional cost savings opportunities. A s we implement these synergy and cost-saving initiatives, we may not realize anticipated savings or other benefits from one or more of the initiatives in the amounts or within the time periods we expect. The cost-reduction actions could negatively impact or disrupt our operations. The impact of these cost-reduction actions on our operations may be influenced by many factors, including declines in employee morale and the potential inability to meet operational targets due to our inability to retain or recruit key employees. Additionally, the cost-reduction actions could lead to the deterioration or failure of our operational and financial controls due to an inability to properly control and manage change, employee attrition, financial and operating system conversion and other factors that could adversely impact our business during the implementation or respective cost-reduction initiatives. If we experience any of these circumstances or otherwise fail to realize the anticipated savings or benefits from our synergy and cost-saving initiatives, our financial condition, results of operations and cash flows could be materially and adversely affected. We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not 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, punchthroughs, 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, 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, collision, damage from severe weather and marine life infestations. 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 incorporate a broad exclusion that limits the customer's indemnity rights 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 also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of 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, no assurance can be given that we will be able to obtain insurance against all potential risks and hazards, or that we will be able to maintain the same levels and types of coverage that we have maintained in the past. Our financial leverage and negative cash flow could cause insurance companies to increase our premiums and deductibles or limit our coverage amounts. 32 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 offer or demand significantly higher premiums or deductibles to cover these risks. Additionally, a significant number of energy-related insurance claims may increase insurance premiums to energy companies. Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for all of our claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, certain loss or damage to property onboard our rigs and losses relating to terrorist acts or strikes. 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, and we have a larger concentration of jack-up rigs in the U.S. Gulf of Mexico than most of our competitors. We had four jackup rigs and four floaters in the U.S. Gulf of Mexico as of December 31, 2020. Damage caused by high winds and turbulent seas could result in 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 floaters 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 rigs in the U.S. Gulf of Mexico for the aforementioned reasons. Accordingly, we have retained the risk of loss or damage for our jackups and floaters arising from windstorm damage in the U.S. Gulf of Mexico. 33 We have established operational procedures designed to mitigate risk to our jackups 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. Our annual insurance policies are up for renewal effective May 31, 2021, and 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. 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 ten 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 the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us with an early termination payment. 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 rigs contracted to national oil companies with commensurate additional contractual risks. 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, such as the Persian Gulf area. 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. Rig construction, upgrade, enhancement and reactivation 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. We currently have two ultra-deepwater drillships under construction. In the future, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. As a result of current market conditions, we may seek to delay delivery of our rigs under construction. During the third quarter of 2019, we entered into amendments to our construction agreements with the shipyard for the VALARIS DS-13 and VALARIS DS-14 rigs to provide for two-year extensions of the delivery date of each rig into 2021 and 2022, respectively. On December 30, 2020, we reached an agreement in principle to amend and assume pursuant to section 365 of the Bankruptcy Code the two construction agreements, which was subsequently modified through further negotiations. On February 26, 2021, we entered into amended agreements that extend the delivery date for both new rigs to December 31, 2023. During periods of heightened rig construction projects, shipyards and third-party equipment vendors may be under significant resource constraints to meet delivery obligations. Such 34 constraints may lead to substantial delivery and commissioning delays, equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction, 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 construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, 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, • damage to shipyard facilities or construction work-in-progress, 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 constructing, 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. With respect to VALARIS DS-13 and VALARIS DS-14, if we were to secure contracts for these rigs, we would be subject to the risk of delays and other hazards impacting the viability of such contracts, which could have a material adverse effect on our financial position, operating results or cash flows. In addition, we believe 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 the possible technological obsolescence of the rig. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives. 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. 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 35 our business. Historically, competition for the labor required for drilling operations and construction projects was intense as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry. During such periods of intensified competition, it is more difficult and costly to recruit and retain qualified employees, especially in foreign countries that require a certain percentage of national employees. The recent prolonged industry downturn and reductions in offshore personnel wages may further reduce the number of qualified personnel available. If competition for labor were to intensify in the future, we could experience an increase in operating expenses, with a resulting reduction in net income, and our ability to fully staff and operate our rigs could be negatively affected. We may be required to maintain or 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. These conditions could further increase our costs or limit our ability to fully staff and operate our rigs. We have historically made substantial capital 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. We have historically made substantial capital 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 and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations relating to 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. As a result, we may be required to take our 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 older 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 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 changes in laws and regulations (or 36 interpretation thereof) 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. 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. Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility. 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 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. 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. Recent deterioration in the business environment has reduced the number of available suppliers, and the imposition of further public health measures affecting supply chain and logistics due to the COVID-19 pandemic may negatively impact our suppliers. Additionally, the longer that our Chapter 11 Cases continue, the more likely it is that our suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, thus adversely impacting our operations and revenues and/or our operating costs. 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 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. Contract preparation expenses vary based on the scope and length of contract preparation required. 37 Our information technology systems, including rig operating systems, are subject to cybersecurity risks and threats. We depend on technologies, systems and networks to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. The risks associated with 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; loss of intellectual property, proprietary information or customer and vendor 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, 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, including under data privacy laws and regulations such as the European Union General Data Protection Regulation and, with effect from January 1, 2021, such regulation as amended and forming part of the law of the United Kingdom, disruption to our operations and damage our reputation, which 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. Risk Related to Our Indebtedness and Ordinary Shares Our Class A ordinary shares have been delisted from the NYSE. Effective September 14, 2020, our Class A ordinary shares were delisted from the NYSE. Since August 19, 2020, our shares have been traded on the OTC Pink Open Market under the symbol “VALPQ.” We can provide no assurance that our ordinary shares will continue to trade on this market, whether broker-dealers will continue to provide public quotes of our ordinary shares on this market, whether the trading volume of our ordinary shares will be sufficient to provide for an efficient trading market or whether quotes for our ordinary shares will continue on this market in the future, which could result in significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell our ordinary shares. The accounting method for our 2024 Convertible Notes could have a material effect on our reported financial results. Based on our current plan of reorganization, we expect our 3.00% exchangeable senior notes due 2024 (the “2024 Convertible Notes”) to be cancelled with holders receiving the treatment as set forth in the plan of reorganization. However, to the extent the 2024 Convertible Notes (as defined below) are not cancelled, under U.S. GAAP, we must separately account for the liability and equity components of convertible debt instruments, such as our 2024 Convertible Notes in a manner that reflects the issuer’s economic interest cost. The equity component representing the conversion feature is recorded in additional paid-in capital within the shareholders’ equity section of our consolidated balance sheet. The equity component is not remeasured if we continue to meet certain conditions for equity classification under U.S. GAAP, including maintaining the ability to settle the 2024 Convertible Notes entirely in shares. During periods in which we are unable to meet the conditions for equity classification, the equity component or a portion thereof would be remeasured through earnings, which could adversely affect our operating results. If the 2024 Convertible are not cancelled pursuant to our plan reorganization, upon conversion of the 2024 Convertible Notes, holders will receive cash, our Class A ordinary shares or a combination thereof, at our election. Our intent is to settle the principal amount of the 2024 Convertible Notes in cash upon conversion. If the conversion value exceeds the principal amount (i.e., our share price exceeds the exchange price on the date of conversion), we expect to deliver shares equal to our conversion obligation in excess of the principal amount. During each respective reporting period that our average share price exceeds the exchange price, an assumed number of shares required to 38 settle the conversion obligation in excess of the principal amount will be included in the denominator for our computation of diluted earnings per share using the treasury stock method. If we are unable to demonstrate our intent to settle the principal amount in cash, or are otherwise unable to utilize the treasury stock method, our diluted earnings per share would be adversely affected. See " Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes. Transfers of our Class A ordinary shares may be subject to stamp duty or stamp duty reserve tax (“SDRT”) in the U.K., which would increase the cost of dealing in our Class A ordinary shares. Stamp duty and/or SDRT are imposed in the U.K. on certain transfers of chargeable securities (which include shares in companies incorporated in the U.K.) at a rate of 0.5% of the consideration paid for the transfer. Certain transfers of shares to depositary receipt facilities or clearance systems providers are charged at a higher rate of 1.5%. Pursuant to arrangements that we entered into with the Depository Trust Company (“DTC”), our Class A ordinary shares are eligible to be held in book entry form through the facilities of DTC. Transfers of shares held in book entry form through DTC will not attract a charge to stamp duty or SDRT in the U.K. A transfer of the shares from within the DTC system out of DTC and any subsequent transfers that occur entirely outside the DTC system will attract a charge to stamp duty at a rate of 0.5% of any consideration, which is payable by the transferee of the shares. Any such duty must be paid (and the relevant transfer document stamped by Her Majesty's Revenue & Customs (“HMRC”)) before the transfer can be registered in the share register of Valaris plc. If a shareholder decides to redeposit shares into DTC, the redeposit will attract SDRT at a rate of 1.5% of the value of the shares. We have put in place arrangements with our transfer agent to require that shares held in certificated form cannot be transferred into the DTC system until the transferor of the shares has first delivered the shares to a depository specified by us so that SDRT may be collected in connection with the initial delivery to the depository. Any such shares will be evidenced by a receipt issued by the depository. Before the transfer can be registered in our share register, the transferor will also be required to provide the transfer agent sufficient funds to settle the resultant liability for SDRT, which will be charged at a rate of 1.5% of the value of the shares. Following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC announced that it would not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into a depositary receipt facility or clearance system provider, such as DTC. Further, in its 2017 Autumn Budget the U.K. government announced that it would not reintroduce the Stamp Duty and Stamp Duty Reserve Tax 1.5% charge on the issue of shares (and transfers integral to capital raising) into overseas clearance services and depositary receipt systems following the U.K.’s exit from the European Union. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT, which could have a material effect on the cost of trading in our shares. If our Class A ordinary shares are not eligible for continued deposit and clearing within the facilities of DTC, then transactions in our securities may be disrupted. The facilities of DTC are widely-used for rapid electronic transfers of securities between participants within the DTC system, which include numerous major international financial institutions and brokerage firms. Currently, all trades of our Class A ordinary shares on the OTC Pink Open Market are cleared and settled on the facilities of DTC. Our Class A ordinary shares are, at present, eligible for deposit and clearing within the DTC system, pursuant to arrangements with DTC whereby DTC accepted our Class A ordinary shares for deposit, clearing and settlement services, and we agreed to indemnify DTC for any stamp duty and/or SDRT that may be assessed upon it as a result of its service as a clearance system provider for our Class A ordinary shares. However, DTC retains sole discretion to cease to act as a clearance system provider for our Class A ordinary shares at any time. 39 If DTC determines at any time that our shares are no longer eligible for deposit, clearing and settlement services within its facilities, trading in such shares would be disrupted. In this event, DTC has agreed it will provide us advance notice and assist us, to the extent possible, with efforts to mitigate adverse consequences. While we would pursue alternative arrangements to preserve our listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our Class A ordinary shares. We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements. Directors of Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in their certificates of incorporation that were not already issued or reserved. The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors of a U.K. public limited company may only allot shares with the prior authorization of an ordinary resolution of the company’s shareholders, which authorization must state the maximum amount of shares that may be allotted under it and specify the date on which it will expire, which must not be more than five years from the date on which the shareholder resolution is passed. An ordinary resolution was passed by shareholders at our last annual general meeting on June 15, 2020 to authorize the allotment of up to a prescribed amount of additional shares until the conclusion of the next annual general meeting or the close of business on August 19, 2021 (whichever is earlier). English law also generally provides shareholders pre-emption rights over new shares that are issued for cash. However, it is possible, where the board of directors is generally authorized to allot shares, to exclude pre-emption rights by a special resolution of the shareholders or by a provision in the articles of association. Such exclusion of pre-emption rights will commonly cease to have effect at the same time as the general allotment authority to which it relates is revoked or expires. If the general allotment authority is renewed, the authority excluding pre-emption rights may also be renewed by a special resolution of the shareholders. Two special resolutions were passed, in conjunction with an allotment authority at our last annual general meeting on June 15, 2020, to disapply pre-emption rights in respect of new shares up to a prescribed amount, both generally and in connection with an acquisition or specified capital investment, until the conclusion of the next annual general meeting or the close of business on August 19, 2021 (whichever is earlier). Our shares are not traded on a “recognized investment exchange” for the purposes of English law and we are therefore only able to conduct “off-market” purchases of our shares. English law generally prohibits a company from repurchasing its own shares by way of "off-market" purchases without approval by ordinary resolution of the shareholders of the terms of the contract by which the purchase(s) is affected. Such approval may only last for a maximum period of five years after the date on which the resolution is passed. An ordinary resolution was passed at our annual shareholder meeting on May 21, 2018 authorizing us to make "off-market" purchases of our own shares pursuant to certain purchase agreements for a five-year term. We can provide no assurances that future shareholder approvals required for the matters described above will be forthcoming. If all or any of such approvals are not granted, our flexibility with respect to certain capital management matters could be reduced which could, in turn, deprive our shareholders of substantial benefits. Our articles of association contain anti-takeover provisions; however, the Company is not subject to the U.K.'s City Code on Takeovers and Mergers. Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all shareholders of the Company are treated equally and fairly and receive an optimum price for their shares and the long-term success of the Company is safeguarded. Under English law, it may not be possible to implement these provisions in all circumstances. 40 The Code only applies to an offer for a public company that is registered in the U.K. (or the Channel Islands or the Isle of Man) and the securities of which are not admitted to trading on a regulated market in the U.K. (or the Channel Islands or the Isle of Man) if the company is considered by the takeover panel (the "Takeover Panel") to have its place of central management and control in the U.K. (or the Channel Islands or the Isle of Man). This is known as the "residency test." The test for central management and control under the Code is different from that used by the U.K. tax authorities. Under the Code, the Takeover Panel will look to where the majority of the directors of the company are residents for the purposes of determining where the company has its place of central management and control. Accordingly, the Takeover Panel has previously indicated that the Code does not apply to the Company and the Company's shareholders therefore do not have the benefit of the protections the Code affords, including, but not limited to, the requirement that a person who acquires an interest in shares carrying 30% or more of the voting rights in the Company must make a cash offer to all other shareholders at the highest price paid in the 12 months before the offer was announced. English law requires that we meet certain additional financial requirements before declaring dividends and returning funds to shareholders. Under English law, we are only able to declare dividends and return funds to our shareholders out of the accumulated distributable reserves on our statutory balance sheet. Distributable reserves are a company’s accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. Realized profits are created through the remittance of profits of certain subsidiaries to our parent company in the form of dividends. English law also provides that a public company can only make a distribution if, among other things (a) the amount of its net assets (that is, the total excess of assets over liabilities) is not less than the total of its called up share capital and non-distributable reserves and (b) if, and to the extent that, the distribution does not reduce the amount of its net assets to less than that total. We may be unable to remit the profits of our subsidiaries in a timely or tax efficient manner. If at any time we do not have sufficient distributable reserves to declare and pay quarterly dividends, we may undertake a reduction in the capital of the Company, in addition to the reduction of capital undertaken in 2014, to reduce the amount of our share capital and non-distributable reserves and to create a corresponding increase in our distributable reserves out of which future distributions to shareholders can be made. To comply with English law, a reduction of capital would, in addition to the restrictions described above, be subject to (a) approval of shareholders at a general meeting by special resolution; (b) confirmation by an order of the English Courts and (c) the Court order being delivered to and registered by the Registrar of Companies in England. If we were to pursue a reduction of capital of the Company as a course of action, and failed to obtain the necessary approvals from shareholders and the English Courts, we may undertake other efforts to allow the Company to declare dividends and return funds to shareholders. Legal, Regulatory and Tax Risks Failure to comply with anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act, 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 41 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, cash flows or the availability of funds under our revolving credit facility. 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, particularly in the U.S. Gulf of Mexico, 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. As a result of jackup rig fitness requirements during hurricane seasons issued by BSEE and its predecessor agency, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig's hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico. Current or future Notice to Lessees from the U.S. Department of the Interior or other rules, directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico. Proposed revisions to the 2016 Well Control Rule, which imposed new requirements for well-control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment, would revise requirements for well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions are targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing certain unnecessary regulatory burdens imposed under the existing regulations. The proposed revisions have not yet been finalized. Although only operators are currently required to have a SEMS, BSEE has in the past stated that future rulemaking may require offshore drilling contractors to implement their own SEMS programs. The current SEMS regulations, which require written agreements between operators and contractors regarding the contractors’ support of the operators' safety and environmental policies at the worksite (including requirements for personnel training and written safe work practices), and the possibility of additional SEMS rules for contractors could expose us to increased costs. Finally, since 2014, the United States Coast Guard has proposed new regulations that would impose GPS equipment and positioning requirements for drilling rigs operating in the U.S. Gulf of Mexico and issued notices 42 regarding the development of guidelines for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the MTSA, including our rigs. 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. 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 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. Although OPA 90 provides for certain limits of liability, such limits are not applicable where there is any safety violation or where gross negligence is involved. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results or cash flows. Further, remedies under the Clean Water Act and related legislation and OPA 90 do not preclude claims under state regulations or civil claims for damages to third parties under state laws. High profile and catastrophic events, including the 2010 Macondo well incident, have heightened governmental and environmental concerns about the risks associated with 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 43 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. 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 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 and the Katowice climate conference in December 2018. 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, 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 environmental initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations and our access to capital. 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 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, to the extent that societal pressures or political or other factors are involved, 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 tradeoffs that inevitably occur in connection with such processes. 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 plc is incorporated in the United Kingdom (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 (including as a result of the Atwood acquisition completed in 2017). 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 44 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 45 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. Investor enforcement of civil judgments against us may be more difficult. Because we are a public limited company incorporated under the Laws of England and Wales, investors could experience difficulty enforcing judgments obtained against us in U.S. courts. In addition, it may be more difficult (or impossible) to bring some types of claims against us in courts in England than it would be to bring similar claims against a U.S. company in a U.S. court. 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 environment, social and governance (“ESG”) matters, financial restructuring, increased borrowing, dividends, share repurchases or even sales of assets or 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 83%, 85% and 87% of our total consolidated revenues during 2020, 2019 and 2018, 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, 46 • 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 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 sometimes 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 47 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 occasionally 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 use 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 have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding 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 48 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. The U.K.'s withdrawal from the E.U. may have a negative effect on economic conditions, financial markets and our business. In June 2016, a referendum was held in the U.K. which resulted in a majority voting in favor of the U.K. withdrawing from the E.U. (commonly referred to as “Brexit”). Pursuant to legislation approved by the U.K. Parliament and the E.U. Parliament in January 2020, the U.K. withdrew from the E.U. with effect from 11 p.m. (GMT) on January 31, 2020 on the terms of a withdrawal agreement agreed between the U.K. and the E.U. in October 2019 (the “Withdrawal Agreement”). The Withdrawal Agreement provided for the U.K.’s withdrawal to be followed by a “transition period”, during which, in summary, the U.K. was not a member of the E.U. but most E.U. rules and regulations continued to apply to the U.K. During the transition period, the U.K. and the E.U. sought to negotiate the terms of a long-term trading relationship between the U.K. and the E.U. based on a “Political Declaration” agreed between the U.K. and the E.U. in October 2019. The transition period expired on December 31, 2020. On December 24, 2020, the European Commission and the United Kingdom reached agreement on the terms of the U.K.’s future relationship with the E.U. (the “Trade and Cooperation Agreement”). As negotiations concerning the terms of the Trade and Cooperation Agreement could only be finalized shortly before the expiry of the transition period, the European Commission has determined to apply the Trade and Cooperation Agreement provisionally with effect from January 1, 2021, until it can be formally ratified by the European Union. This will require the European Parliament to give its consent to the Trade and Cooperation Agreement and the Council of the European Union to adopt a formal decision on its conclusion. It is currently expected that such processes will be completed during the first quarter of 2021. Many of the practical effects of the Trade and Cooperation Agreement will only become clear with the passage of time and at present it is not possible for us to estimate with certainty whether its implementation will have a material adverse effect on our financial position, operating results or cash flows. While the Trade and Cooperation Agreement 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 also seeks to minimize trade disruption arising from technical and administrative barriers to trade, there can be no guarantee that the 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 49 or cash flows. Approximately 15% of our total revenues were generated in the U.K. for the year ended December 31, 2020. Item 1B. Unresolved Staff Comments None. 50 Item 2. Properties Contract Drilling Fleet The following table provides certain information about the rigs in our drilling fleet as of February 22, 2021: 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' United Kingdom Preservation stacked (1) 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' United Kingdom Preservation stacked (1) VALARIS DS-9 Drillship 2015 Dynamically Positioned 12,000'/40,000' Spain Preservation stacked (1) VALARIS DS-10 Drillship 2015 Dynamically Positioned 12,000'/40,000' Nigeria Under contract VALARIS DS-11 Drillship 2013 Dynamically Positioned 12,000'/40,000' Spain Preservation stacked (1) VALARIS DS-12 Drillship 2013 Dynamically Positioned 12,000'/40,000' Angola Under contract VALARIS DS-13 Drillship Under construction 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' Mexico Under contract VALARIS DS-16 Drillship 2014 Dynamically Positioned 12,000'/40,000' Spain Preservation stacked (1) 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 8503 Semisubmersible 2010 Dynamically Positioned 8,500'/37,500' Gulf of Mexico Preservation stacked (1) VALARIS 8505 Semisubmersible 2012 Dynamically Positioned 8,500'/35,000' Gulf of Mexico Under contract VALARIS 8506 Semisubmersible 2012 Dynamically Positioned 8,500'/35,000' Gulf of Mexico Preservation stacked (1) VALARIS DPS-1 Semisubmersible 2012 F&G ExD Millennium 10,000'/35,000' Malaysia Available VALARIS MS-1 Semisubmersible 2011 F&G ExD Millennium 8,200'/40,000 Australia Under contract Jackups VALARIS JU-22 Jackup 1980/2011 MLT 116-C 313'/25,000' Saudi Arabia Leased to ARO drilling VALARIS JU-36 Jackup 1981/2011 MLT 116-C 300'/25,000' Saudi Arabia Leased to ARO drilling VALARIS JU-37 Jackup 1981/2011 MLT 116-C 300'/25,000' Saudi Arabia Leased to ARO drilling VALARIS JU-54 Jackup 1982/2004 F&G L-780 MOD II-C 300'/25,000' Saudi Arabia Under contract VALARIS JU-67 Jackup 1976/2005 MLT 84-CE 350'/30,000' Indonesia Under contract VALARIS JU-72 Jackup 1981/2011 Hitachi K1025N 225'/25,000' United Kingdom Under contract VALARIS JU-75 Jackup 1999 MLT Super 116-C 400'/30,000' Gulf of Mexico Preservation stacked (1) VALARIS JU-76 Jackup 2000 MLT Super 116-C 350'/30,000' Saudi Arabia Under contract VALARIS JU-92 Jackup 1982/2003 MLT 116-C 210'/25,000' United Kingdom Under contract VALARIS JU-100 Jackup 1987/2009 MLT 150-88-C 328'/25,000' Denmark Preservation stacked (1) VALARIS JU-101 Jackup 2000/2010 KFELS MOD V-A 400'/30,000' United Kingdom Preservation stacked (1) VALARIS JU-102 Jackup 2002 KFELS MOD V-A 400'/30,000' Gulf of Mexico Under contract VALARIS JU-104 Jackup 2002/2011 KFELS MOD V-B 400'/30,000' UAE Preservation stacked (1) VALARIS JU-106 Jackup 2005 KFELS MOD V-B 400'/30,000' Indonesia Under contract VALARIS JU-107 Jackup 2006 KFELS MOD V-B 400'/30,000' Australia Under contract VALARIS JU-108 Jackup 2007/2009 KFELS MOD V-B 400'/30,000' Saudi Arabia Under contract VALARIS JU-109 Jackup 2008 KFELS MOD V-Super B 350'/35,000' Namibia Preservation stacked (1) 51 Rig Name Rig Type Year Built/ Rebuilt Design Maximum Water Depth/ Drilling Depth Location Status Jackups VALARIS JU-110 Jackup 2015 KFELS MOD V-B 400'/35,000' Qatar Under contract VALARIS JU-111 Jackup 2003 KFELS MOD V Enhanced B-Class 400'/36,000' Malta Preservation stacked (1) VALARIS JU-113 Jackup 2012 Baker Marine Pacific Class 400 400'/30,000' Philippines Preservation stacked (1) VALARIS JU-114 Jackup 2012 Baker Marine Pacific Class 400 400'/30,000' Philippines Preservation stacked (1) VALARIS JU-115 Jackup 2013 Baker Marine Pacific Class 400 400'/30,000' Thailand Under contract VALARIS JU-116 Jackup 2008/2018 LT 240- C 375'/35,000' Saudi Arabia Leased to ARO drilling VALARIS JU-117 Jackup 2009 LT 240- C 350'/35,000' Gulf of Mexico Available VALARIS JU-118 Jackup 2012 LT 240- C 350'/35,000 Mexico Under contract VALARIS JU-120 Jackup 2013 KFELS Super A 400'/40,000' United Kingdom Under contract VALARIS JU-121 Jackup 2013 KFELS Super A 400'/40,000' United Kingdom Under contract VALARIS JU-122 Jackup 2013 KFELS Super A 400'/40,000' United Kingdom Under contract VALARIS JU-123 Jackup 2016 KFELS Super A 400'/40,000' United Kingdom Under contract VALARIS JU-140 Jackup 2016 LT Super 116E 340'/30,000' Saudi Arabia Under contract VALARIS JU-141 Jackup 2016 LT Super 116E 340'/30,000' Saudi Arabia Under contract VALARIS JU-142 Jackup 2008 LT Super 116-E 350'/36,000' Malta Preservation stacked (1) VALARIS JU-143 Jackup 2010/2018 LT EXL Super 116-E 350'/35,000' Saudi Arabia Leased to ARO drilling VALARIS JU-144 Jackup 2010 LT Super 116-E 350'/35,000' Mexico Under contract VALARIS JU-145 Jackup 2010 LT Super 116-E 350'/35,000' Gulf of Mexico Preservation stacked (1) VALARIS JU-146 Jackup 2011/2018 LT EXL Super 116-E 320'/35,000' Saudi Arabia Leased to ARO drilling VALARIS JU-147 Jackup 2012/2019 LT Super 116-E 350'/30,000' Saudi Arabia Leased to ARO drilling VALARIS JU-148 Jackup 2013/2019 LT Super 116-E 350'/30,000' Saudi Arabia Leased to ARO drilling VALARIS JU-247 Jackup 1998 LT Super Gorilla 400'/35,000' United Kingdom Available VALARIS JU-248 Jackup 2001/2014 LT Super Gorilla 400'/35,000' United Kingdom Under contract VALARIS JU-249 Jackup 2001 LT Super Gorilla 400'/35,000' United Kingdom Preservation stacked (1) VALARIS JU-250 Jackup 2003 LT Super Gorilla XL 550'/35,000' Saudi Arabia Leased to ARO drilling VALARIS JU-290 Jackup 2011 KEFLS N Class 435'/35,000' Norway Under contract VALARIS JU-291 Jackup 2011 KEFLS N Class 400'/35,000' Norway Under contract VALARIS JU-292 Jackup 2011 KEFLS N Class 400'/35,000' Norway 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) The Amended RSA provides that on or before the effective date of the reorganization, the construction contracts for these rigs shall be rejected under Section 365 of the Bankruptcy Code, unless otherwise agreed between the shipyard and the Company with the consent of required Consenting Noteholders. If rejected, it is contemplated that we would have to pay an amount equal to the liquidation recovery, which is the amount the contract counterparty would be entitled to receive or retain if the applicable Company entity was liquidated under chapter 7 of the Bankruptcy Code. Prior to December 31, 2020, a Stipulation was filed with the Bankruptcy Court which included an Assumption Term Sheet stating amended terms of these construction agreements. 52 Following further negotiations, we entered into amended agreements with the shipyard on February 26, 2021 that become 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 remove any Company guarantee. 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 8503 and VALARIS 8505, 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. Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. We believe all our rigs are in good condition. As of February 22, 2021, we owned all rigs in our fleet. We also manage the drilling operations for two platform rigs owned by a third-party. We lease our executive offices in London, England in addition to office space in Houston, Aberdeen, Indonesia, Malaysia, Mexico, Brazil, Trinidad, Nigeria, The Netherlands, Saudi Arabia, Thailand, and Norway. We own offices and other facilities in Louisiana, Angola, Australia, Aberdeen and Brazil. 53 Item 3. Legal Proceedings UMB Bank Lawsuit On March 19, 2020, UMB Bank, National Association (“UMB”), the purported indenture trustee for four series of Valaris notes, filed a lawsuit in Harris County District Court in Houston, Texas. The lawsuit was filed against Valaris plc, two legacy Rowan entities, two legacy Ensco entities and the individual directors of the two legacy Rowan entities. The complaint alleges, among other things, breach of fiduciary duty, aiding and abetting breach of fiduciary duty and fraudulent transfer in connection with certain intercompany transactions occurring after completion of the Rowan merger and the Rowan entities’ guarantee of Valaris’ revolving credit facility. In addition to an unspecified amount of damages, the lawsuit seeks to void and undo all historical transfers of cash or other assets from legacy Rowan entities to Valaris and its other subsidiaries and the internal reorganization transaction. On August 18, 2020, Valaris and certain of its affiliates entered into the Original RSA, including the noteholders that directed UMB to file the lawsuit. Under the Original RSA and the Amended RSA, the lawsuit is stayed by agreement throughout the pendency of the bankruptcy proceeding unless the Original RSA terminates at which point each party reserves its rights to argue whether the case should proceed while in bankruptcy. If the Bankruptcy Court confirms a plan based on the transactions set forth in the Original RSA or the Amended RSA, the lawsuit will be dismissed with prejudice. On August 24, 2020, the parties filed a joint notice staying the case. If the Original RSA terminates and the case in fact proceeds, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect final disposition of this matter 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 the proceedings. Shareholder Class Action On August 20, 2019, plaintiff Xiaoyuan Zhang, a purported Valaris shareholder, filed a class action lawsuit on behalf of Valaris shareholders against Valaris plc and certain of our executive officers, alleging violations of federal securities laws. The complaint cites general statements in press releases and SEC filings and alleges that the defendants made false or misleading statements or failed to disclose material information regarding the performance of our ultra-deepwater segment, among other things. The complaint asserts claims on behalf of a class of investors who purchased Valaris plc shares between April 11, 2019 and July 31, 2019. The court appointed a lead plaintiff and lead counsel. The case has now been stayed in light of the Valaris plc bankruptcy filing, with the exception that lead plaintiff may continue efforts to serve certain defendants and may file an amended complaint. At this time, we are unable to predict the outcome of these matters or the extent of any resulting liability. 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 2017, 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 $482,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2020. 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 54 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. Item 4. Mine Safety Disclosures Not applicable. 55 PART II Item 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities Market Information As a result of the Chapter 11 Cases and in accordance with Section 802.01D of the NYSE Listed Company Manual, on August 19, 2020, we were notified by NYSE of its determination to indefinitely suspend trading of the Company’s Class A ordinary shares and to commence proceedings to delist the Company’s Class A ordinary shares from the NYSE. Our Class A ordinary shares were delisted from the NYSE effective September 14, 2020. Since that time, the shares have been quoted on the OTC Pink Open Market under the symbol “VALPQ.” We can provide no assurance that our ordinary shares will continue to trade on this market, whether broker-dealers will continue to provide public quotes of our ordinary shares on this market, whether the trading volume of our ordinary shares will be sufficient to provide for an efficient trading market or whether quotes for our ordinary shares will continue on this market in the future. These recent developments could result in significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell shares of our ordinary shares. Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 204 shareholders of record on February 1, 2021. Dividends The declaration and amount of dividends is at the discretion of our Board of Directors. No dividends have been declared since the first quarter of 2019. Exchange Controls There are no U.K. government laws, decrees or regulations that restrict or affect the export or import of capital, including but not limited to, foreign exchange controls on remittance of dividends on our ordinary shares or on the conduct of our operations. U.K. Taxation The following paragraphs are intended to be a general guide to current U.K. tax law and what is understood to be HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by us and stamp duty and SDRT on the transfer of our shares. In addition, the following paragraphs relate only to persons who for U.K. tax purposes are beneficial owners of the shares. These paragraphs may not relate to certain classes of holders or beneficial owners of shares, such as our employees or directors, persons who are connected with us, persons who could be treated for U.K. tax purposes as holding their shares as carried interest, insurance companies, charities, collective investment schemes, pension schemes, trustees or persons who hold shares other than as an investment, or U.K. resident individuals who are not domiciled in the U.K. or who are subject to split-year treatment. These paragraphs do not describe all of the circumstances in which shareholders may benefit from an exemption or relief from taxation. It is recommended that all shareholders obtain their own taxation advice. In particular, any shareholders who are non-U.K. resident or domiciled are advised to consider the potential impact of any relevant double tax treaties, including the Convention between the United States of America and the United Kingdom for the Avoidance of Double Taxation with respect to Taxes on Income, to the extent applicable. 56 U.K. Taxation of Dividends U.K. Withholding Tax - Dividends paid by us will not be subject to any withholding or deduction for, or on account of, U.K. tax, irrespective of the residence or the individual circumstances of the shareholders. U.K. Income Tax - An individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. An individual shareholder who is not resident in the U.K. will not be subject to U.K. income tax on dividends received from us, unless that shareholder carries on (whether alone or in partnership) any trade, profession or vocation through a branch or agency in the U.K. and shares are used by, or held by or for, that branch or agency. In these circumstances, the non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. The tax treatment of dividends paid by the Company to individual shareholders is as follows: • dividends paid by the Company will not carry a tax credit, • all dividends received by an individual shareholder from the Company (or from other sources) will, except to the extent that they are earned through an Individual Savings Account, self-invested personal pension plan or other regime which exempts the dividends from income tax, form part of the shareholder's total income for income tax purposes, • a nil rate of income tax will apply to the first £2,000 of taxable dividend income received by an individual shareholder in the tax year 2020/2021 (the "Nil Rate Amount"), regardless of what tax rate would otherwise apply to that dividend income, • any taxable dividend income received by an individual shareholder in a tax year in excess of the Nil Rate Amount will be taxed at a special rate, as set out below, and • that tax will be applied to the amount of the dividend income actually received by the individual shareholder (rather than to a grossed-up amount). Where a shareholder’s taxable dividend income for a tax year exceeds the Nil Rate Amount, the excess amount will, subject to the availability of any income tax personal allowance, be subject to income tax at the following rates for the tax year 2020/2021: • at the rate of 7.5%, to the extent that the excess amount falls below the threshold for the higher rate of income tax, • at the rate of 32.5%, to the extent that the excess amount falls above the threshold for the higher rate of income tax but below the threshold for the additional rate of income tax, or • at the rate of 38.1%, to the extent that the excess amount falls above the threshold for the additional rate of income tax. In determining whether and, if so, to what extent the relevant dividend income falls above or below the threshold for the higher rate of income tax or, as the case may be, the additional rate of income tax, the shareholder’s total dividend income for the tax year in question (including the part within the Nil Rate Amount) will be treated as the highest part of the shareholder’s total income for income tax purposes. U.K. Corporation Tax - Unless an exemption is available, as discussed below, a corporate shareholder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from us. A corporate shareholder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from 57 us, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate shareholder may, depending on its individual circumstances (and if no exemption is available), be subject to U.K. corporation tax on dividends received from us. The main rate of corporation tax payable with respect to dividends received from us in the financial year 2020 is 19%. If dividends paid by us fall within any of the exemptions from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate shareholder generally will be exempt from U.K. corporation tax. Generally, the conditions for one or more of those exemptions from U.K. corporation tax on dividends paid by us should be satisfied, although the conditions that must be satisfied in any particular case will depend on the individual circumstances of the relevant corporate shareholder. Shareholders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us, unless the dividends are received as part of a tax advantage scheme. Shareholders that are not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us on the basis that the shares should be regarded as non-redeemable ordinary shares. Alternatively, shareholders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from us if they hold shares representing less than 10% of our issued share capital, would be entitled to less than 10% of the profits available for distribution to our equity-holders and would be entitled on a winding up to less than 10% of our assets available for distribution to such equity-holders. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such shareholders if a dividend is made as part of a scheme that has a main purpose of falling within the exemption from U.K. corporation tax. U.K. Taxation of Capital Gains U.K. Withholding Tax - Capital gains accruing to non-U.K. resident shareholders on the disposal of shares will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the relevant shareholder. U.K. Capital Gains Tax - A disposal of shares by an individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable capital gain or an allowable loss for the purposes of U.K. capital gains tax (“CGT”). An individual shareholder who temporarily ceases to be resident in the U.K. for a period of five years or less and who disposes of his or her shares during that period of temporary non-residence may be liable for CGT on a taxable capital gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules. An individual shareholder who is not resident in the U.K. will not be subject to CGT on capital gains arising on the disposal of their shares, unless that shareholder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the shares were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the shareholder through the branch or agency. In these circumstances, the relevant non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to CGT on chargeable gains arising from a disposal of his or her shares. The rate of CGT in the tax year 2020/2021 is: • 10%, to the extent that the shareholder's total taxable gains and taxable income in a given year, including any chargeable gains arising from a disposal of his or her shares ("Total Taxable Gains and Income"), are less than or equal to the upper limit of the income tax basic rate band applicable to that shareholder in respect of that tax year (the "Band Limit"), and • 20%, to the extent that the shareholder's Total Taxable Gains and Income are more than the Band Limit. 58 U.K. Corporation Tax - A disposal of shares by a corporate shareholder resident in the U.K. may give rise to a chargeable gain or an allowable capital loss for the purposes of U.K. corporation tax. A corporate shareholder not resident in the U.K. will not be liable for U.K. corporation tax on chargeable gains accruing on the disposal of its shares, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares were acquired, used in or for the purposes of the permanent establishment or used in or for the purposes of the trade carried on by the shareholder through the permanent establishment. In these circumstances, the relevant non-U.K. resident shareholder may, depending on its individual circumstances, be subject to U.K. corporation tax on chargeable gains arising from a disposal of its shares. The financial year for U.K. corporation tax purposes runs from April 1 to March 31. The main rate of U.K. corporation tax on chargeable gains is 19% in the financial year 2020. Corporate shareholders may be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which provides relief for the effects of inflation by reference to movements in the U.K. retail price index. Such indexation allowance is calculated only up to and including December 2017. From January 1, 2018, indexation allowance is frozen. Indexation allowance will be calculated for assets acquired before January 1, 2018, irrespective of the date of disposal of the asset. If the conditions of the substantial shareholding exemption are satisfied in relation to a chargeable gain accruing to a corporate shareholder on a disposal of its shares, the chargeable gain will be exempt from U.K. corporation tax. The conditions of the substantial shareholding exemption that must be satisfied will depend on the individual circumstances of the relevant corporate shareholder. One of the conditions of the substantial shareholding exemption that must be satisfied is that the corporate shareholder must have held a substantial shareholding in the Company throughout a 12-month period beginning not more than six years before the day on which the disposal takes place. Ordinarily, a corporate shareholder will not be regarded as holding a substantial shareholding in us unless it (whether alone, or together with other group companies) holds more than 10% of our ordinary share capital. U.K. Stamp Duty and SDRT The discussion below relates to shareholders wherever resident but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply. Special rules also apply in relation to certain stock lending and repurchase transactions. Transfer of Shares held in book entry form via DTC - A transfer of shares held in book entry (i.e., electronic) form within the facilities of the DTC system will not be subject to U.K. stamp duty or SDRT. Transfers of Shares out of, or outside of, DTC - Subject to an exemption for certain low value transactions, a transfer of shares from within the DTC system out of that system or any transfer of shares that occurs entirely outside the DTC system generally will be subject to a charge to ad valorem U.K. stamp duty (normally payable by the transferee) at 0.5% of the purchase price of the shares (rounded up to the nearest multiple of £5). SDRT generally will be payable on an unconditional agreement to transfer such shares at 0.5% of the amount or value of the consideration for the transfer. However, such liability for SDRT generally will be cancelled and any SDRT paid will be refunded if the agreement is completed by a duly-stamped transfer within six years of either the date of the agreement or, if the agreement was conditional, the date when the agreement became unconditional. We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specify, so that stamp duty and/or SDRT may be collected in connection with the initial delivery to the depository. Before such transfer can be registered in our books, the transferor will be required to put in the depository funds to settle the resultant liability for stamp duty and/or SDRT, which will be 1.5% of the value of the shares, and to pay the transfer agent such processing fees as may be established from time to time. 59 Following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC announced that it would not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into a depositary receipt facility or clearance system provider, such as DTC. Further, in its 2017 Autumn Budget, the U.K. government announced that it would not reintroduce the Stamp Duty and Stamp Duty Reserve Tax 1.5% charge on the issue of shares (and transfers integral to capital raising) into overseas clearance services and depositary receipt systems following the U.K.’s exit from the E.U., and HMRC has since confirmed that this charge will remain disapplied under the terms of the European Union (Withdrawal) Act 2018 following the end of the transition period on 31 December 2020. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT, which could have a material effect on the cost of trading in our shares. The above statements are intended only as a general guide to the current U.K. stamp duty and SDRT position. Transfers to certain categories of persons are not liable to U.K. stamp duty or SDRT and transfers to others may be liable at a higher rate than discussed above. 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." Issuer Repurchases of Equity Securities The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2020. Issuer Repurchases of Equity Securities Period Total Number of Securities Repurchased (1) Average Price Paid per Security Total Number of Securities Repurchased as Part of Publicly Announced Plans or Programs (2) Approximate Dollar Value of Securities that May Yet Be Repurchased Under Plans or Programs October 1 - October 31 17,313 $ 0.11 — $ 500,000,000 November 1 - November 30 14,685 $ 0.08 — $ 500,000,000 December 1 - December 31 5,549 $ 0.06 — $ 500,000,000 Total 37,547 $ 0.09 — (1) During the quarter ended December 31, 2020, equity securities were repurchased from employees and non-employee directors by an affiliated employee benefit trust in connection with the settlement of income tax withholding obligations arising from the vesting of share awards. Such securities remain available for re-issuance in connection with employee share awards. (2) Our shareholders approved a repurchase program at our annual shareholder meeting held in May 2018. Subject to certain provisions under English law, including the requirement for Valaris plc to have sufficient distributable reserves and for the Board to conclude that a repurchase is in the best interests of Valaris plc taking into account the interests of relevant stakeholders, we may repurchase up to a maximum of $500.0 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates in May 2023. As of December 31, 2020, there had been no share repurchases under the repurchase program. Our DIP Facility only permits the repurchase of shares of our common stock in certain circumstances and the repurchase of shares would likely require approval of 60 the bankruptcy court. We do not currently expect to make repurchases under the program while Valaris plc remains subject to chapter 11 bankruptcy proceedings.. Item 6. Selected Financial Data Not applicable. 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 61 rigs, with drilling operations in almost every major offshore market across five continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 45 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 nine countries on five continents. 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. 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 regions are generally of a short-term nature due to rig mobility. Following several years of market volatility beginning with oil price declines in 2014, as we entered 2020, we expected that volatility 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 61 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 for the near term, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers to cancel or shorten the duration of many of our 2020 drilling contracts, cancel future drilling programs and seek pricing and other contract concessions, which led to material operating losses and liquidity constraints for us. While there has been some recent improvement to Brent crude oil prices, to approximately $65 per barrel in February 2021, there is still a significant amount of uncertainty around the sustainability of the improvement in oil prices to support a recovery in demand for offshore drilling services. Additionally, the full impact that the pandemic and the decline in 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 outbreak, the effectiveness of the ongoing vaccine rollout, the duration of the oil price and demand decline, and the extent of disruptions to our operations. To date, the COVID-19 pandemic has resulted in only 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. We expect that these challenges will continue for drilling contractors as customers wait to gain additional clarity on commodity pricing and seek to reduce costs in the near-term by attempting to renegotiate existing contract terms. We believe the current market and macro-economic conditions will create a challenging contracting environment through 2021 and into 2022 and potentially beyond. 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 have resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions. These recent events have 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. While we have and are continuing to pursue a variety of cost-cutting measures such as further reductions in corporate overhead and discretionary expenditures, reductions in capital expenditures and an increased focus on operational efficiencies, we determined that based on our significant level of indebtedness and the circumstances described above that a comprehensive restructuring of our indebtedness was needed to improve our financial position. As more fully described in “ Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data", the Company will undergo a financial restructuring that is intended to reduce debt levels substantially, support continued operations during the current lower demand environment and provide a robust financial platform to take advantage of market recovery over the long-term. For additional information related to drilling rig supply and demand, see "Business Environment" below. 62 Chapter 11 Proceedings and Ability to Continue as a Going Concern On August 19, 2020 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As part of the chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”), the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption. On August 18, 2020, the Debtors entered into the Original RSA with the Consenting Noteholders. On February 5, 2021, the Debtors entered into the Amended RSA with the Consenting Lenders and Consenting Noteholders, which contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. Holders of approximately 100% of the total commitments outstanding under our revolving credit facility and holders of approximately 72% of the aggregate amount of our Senior Notes outstanding are party to the Amended RSA. Pursuant to the Amended RSA the holders of the Company's Senior Notes (as defined below) will receive their pro rata share of (1) approximately 39% of new common stock issued after consummation of the restructuring (the “New Equity”) and (2) approximately 97.6% of the subscription rights to participate in the rights offering (the "Rights Offering") through which the Company will offer $550 million of new first lien secured notes (the "New Secured Notes"), which includes the Backstop Premium (as defined below). Additionally, holders of the Senior Notes who participate in the Rights Offering will receive their pro rata share of approximately 29.3% of the New Equity pursuant to the Rights Offering, together with the RCF Lenders (as defined below) who will receive their pro rata share of approximately 0.7% of the New Equity, and senior noteholders who agreed to backstop the Rights Offering will receive their pro rata share of approximately 2.63% of the New Equity, together with 0.07% of the New Equity reserved for RCF Lenders and approximately $48.8 million in New Secured Notes reserved for the holders of the Senior Notes and approximately $1.2 million in New Secured Notes reserved for the RCF Lenders (the "Backstop Premium"). Senior noteholders with respect to certain notes would receive an aggregate cash payment of $26 million in connection with settlement of certain alleged claims against the Company. A reorganization pursuant to the terms of the Amended RSA provided lenders under the revolving credit facility (“RCF Lenders”) with an option to select between two alternative treatments: (1) the ability to participate on a pro rata basis in up to 14% of the Rights Offering plus a recovery of up to 30.8% of the New Equity and up to $45 million in cash, or (2) a pro rata recovery of up to 27.8% of the New Equity and up to $116.2 million in cash. Following the results of that election, the two RCF Lenders who chose to participate in the Rights Offering will receive their pro rata share of (1) approximately 5.3% of the New Equity, (2) approximately 2.4% of the New Secured Notes (and associated New Equity), (3) approximately $7.8 million in cash, and (4) their pro rata share of the Backstop Premium. The RCF Lenders who entered into the Amended RSA and elected not to participate in the Rights Offering will receive their pro rata share of (1) approximately 23.0% of the New Equity, and (2) approximately $96.1 million in cash. The Amended RSA provides that holders of general unsecured claims will receive payment in full or reinstatement pursuant to the Bankruptcy Code (excluding claims against the entities party to, or guaranteeing, the new build contracts to be rejected by the Company, which shall receive their liquidation value unless otherwise agreed). Moreover, if holders of equity interests vote as a class in support of the restructuring, they will each receive their pro rata share of 7-year warrants to purchase up to 7% of New Equity (subject to dilution), with a strike price set at a price per share equal to the value at which the senior noteholders would receive a 100% recovery on their claims including accrued interest up to the Petition Date, as applicable. Lastly, to the extent amounts are borrowed, lenders under the DIP Facility (as defined below) will receive payment in full in cash, unless otherwise agreed and certain other fees owed to the DIP Lenders. 63 The Amended RSA contains certain covenants on the part of Valaris and the Consenting Creditors, including commitments by the Consenting Creditors to vote in favor of a plan of reorganization and commitments of Valaris and the Consenting Creditors to negotiate in good faith to finalize the documents and agreements governing the restructuring. The Amended RSA also provides for certain conditions to the obligations of the parties and for termination upon the occurrence of certain events, including without limitation, the failure to achieve certain milestones and certain breaches by the parties under the Amended RSA. Subject to certain exceptions, under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Chapter 11 Cases. Notwithstanding the general applicability of the automatic stay described above, governmental authorities may determine to continue actions brought under their regulatory powers. Although Valaris intends to pursue the restructuring in accordance with the terms set forth in the Amended RSA, there can be no assurance that Valaris will be successful in completing a restructuring or any other similar transaction on the terms set forth in the Amended RSA, on different terms or at all. Among other things, the Amended RSA includes an outside date milestone requiring the Company’s emergence from chapter 11 by no later than June 15, 2021 (subject to a potential 60-day extension pursuant to the terms of the Amended RSA). Other Chapter 11 Financial Disclosures Pre-petition Charges On August 18, 2020, the Company entered into the Backstop Commitment Agreement with certain backstop parties. In connection with this agreement, the Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date. 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 Statement of Operations for the year ended December 31, 2020 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 Statement of Operations for the year ended December 31, 2020. These costs include legal and other professional advisory service fees pertaining to the Chapter 11 Cases, all adjustments made to the carrying amount of certain pre-petition liabilities reflecting claims expected to be allowed by the Bankruptcy Court, contract items related to rejecting and amending certain operating leases ("Contract items") and DIP Facility fees. 64 The following table provides information about reorganization items incurred during the year ended December 31, 2020 , as of or subsequent to the Petition Date (in millions): Year Ended December 31, 2020 Write-off of unamortized debt discounts, premiums and issuance costs $ 447.9 Contract items (11.5) Reorganization items (non-cash) 436.4 DIP Facility fees 20.0 Professional fees 66.8 Contract items 4.4 Reorganization items (fees) 91.2 Total reorganization items, net $ 527.6 Reorganization items (fees) unpaid $ 61.2 Reorganization items (fees) paid $ 30.0 65 Liabilities Subject to Compromise The Debtors' pre-petition unsecured senior notes and related unpaid accrued interest as of the Petition Date have been classified as Liabilities Subject to Compromise on our Consolidated Balance Sheets. The liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court. Liabilities subject to compromise at December 31, 2020 consist of the following (in millions): December 31, 2020 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 Revolving Credit Facility 581.0 Accrued Interest on Senior Notes, Exchangeable Senior Notes, Debentures 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 until the delivery date. Liquidity and Debt Maturities As discussed in " Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data", we have filed the Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness. The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes and revolving credit facility. Any efforts to enforce payment obligations under the Senior 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, and revolving credit facility are automatically stayed as a result of the filing of the Chapter 11 Cases. The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as $581.0 million outstanding borrowings under our revolving credit facility as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. On September 25, 2020, following approval by the Bankruptcy Court, we entered into a senior secured superpriority debtor-in-possession term loan 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 (the “DIP Facility”) to provide liquidity during the pendency of the Chapter 11 Cases. On 66 February 5, 2021, we entered into an amendment to the Backstop Commitment Agreement, which we expect to provide exit financing in the form of a fully backstopped rights offering to senior noteholders and the RCF Lenders for $550 million of New Secured Notes. We expect the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases. Additionally, we expect the exit financing will provide the necessary liquidity to support ongoing operations and working capital needs. As of December 31, 2020, we had $325.8 million in cash and there were no borrowings outstanding under the DIP Credit Agreement. For the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. There can be no assurance that we will confirm and consummate a plan of reorganization as contemplated by the Amended RSA or complete another plan of reorganization with respect to the Chapter 11 Cases and as such, there is substantial doubt about our ability to continue as a going concern. Further, we have concluded that management’s plans do not alleviate the substantial doubt about our ability to continue as a going concern brought about by the significant risks and uncertainties related to our liquidity and Chapter 11 Cases for a period of one year after the date that the financial statements are issued. See "Liquidity and Capital Resources" below and " Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. Backlog As of December 31, 2020, our backlog was $1.2 billion as compared to $2.5 billion as of December 31, 2019. Our floater backlog declined $641.6 million and our jackup backlog declined $421.7 million. 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. Our other segment backlog declined $184.2 million due to contract concessions and revenues realized. Our backlog excludes ARO's backlog, but includes backlog from our rigs leased to ARO at the contractual rates. Contract rates with ARO are subject to adjustment resulting from the shareholder agreement. See " Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. As revenues are realized and if we experience further customer contract cancellations, we may continue to experience declines in backlog, which would result in a decline in revenues and operating cash flows over the near-term. Contract backlog was adjusted for drilling contracts signed, terminated or concessions granted after each respective balance sheet date but prior to filing each annual report on March 2, 2021 and February 21, 2020, respectively. BUSINESS ENVIRONMENT Floaters The floater contracting environment remains challenging due to limited demand and excess supply. Floater demand has declined significantly following the decline in commodity prices in 2014 which caused our customers to reduce capital expenditures, particularly for capital-intensive, long-lead deepwater projects, resulting in the cancellation and delay of drilling programs. 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. The decline in demand has resulted in the cancellation and delay of drilling programs and the termination of drilling contracts. 67 During 2020, we received notices of termination, requests for concessions, cancellation and/or deferral of drilling programs by operators and we may receive additional requests for concessions, termination and/or deferral notices during the pendency of the current market environment. During the first quarter of 2020, VALARIS DS-12 was awarded a one-well contract that commenced in February 2020. VALARIS MS-1 was awarded a three-well contract that is expected to commence in the second quarter of 2021 and has an estimated duration of 155 days. VALARIS 8505 was awarded a one-well contract that was expected to commence in mid-November 2020, but is now expected to commence in June 2021 with an estimated duration of 80 days. In March 2020, VALARIS DS-8 experienced a non-drilling incident while operating offshore Angola, resulting in the blowout preventer (BOP) stack being disconnected from the riser while the rig was moving between well locations. The BOP stack, which we later recovered, dropped to the seabed floor, clear of any subsea structures. No injuries, environmental pollution or third-party damage resulted from the BOP stack being disconnected. As a result of the incident, the operator terminated the contract. The termination resulted in a decline in our contracted revenue backlog of approximately $150 million. We carried loss of hire insurance covering $602,500 per day, after a 45-day deductible waiting period, through the end of the contract in November 2020. The waiting period expired on April 22, 2020. We received loss of hire insurance recoveries of $118.1 million , which represents the total amount owed to us under the applicable insurance policy. The recovery was recognized and recorded in Other operating income on our Consolidated Statements of Operations. During the second quarter of 2020, the VALARIS DS-7 contract for operations offshore Ghana was terminated. Additionally, contracts awarded in the first quarter of 2020 for VALARIS DS-7 operations offshore Senegal/Mauritania, VALARIS DS-9 operations offshore Brazil and VALARIS MS-1 contract operations offshore Australia were terminated. Further, the VALARIS DPS-1 contract was terminated in June, earlier than the previously scheduled end date of September 2021, and the VALARIS DS-10, VALARIS DS-15 and VALARIS 8505 operated on reduced day rates for various periods during 2020. The VALARIS 5004 operated on a reduced day rate from mid-March to mid-April of 2020, at which point the contract was terminated. During the third quarter of 2020, floater contracting remained challenging and no significant new contracts were executed. In the fourth quarter of 2020, we extended the VALARIS DS-10 and VALARIS DS-18 contracts for an estimated 90 days and 60 days, respectively. In January 2021, we extended the VALARIS DS-12 contract for an estimated 100 days. Our backlog for our floater segment was $205.7 million and $847.3 million as of December 31, 2020 and December 31, 2019, 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. The VALARIS 6002 was sold in January 2020 resulting in an insignificant pre-tax gain. Additionally, the VALARIS 5004 was sold in April 2020 resulting in an insignificant pre-tax loss. During the second quarter of 2020, we began marketing VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6 and classified these rigs as held-for-sale, resulting in an impairment of approximately $14.6 million as the net book value exceeded the fair value less costs to sell. During the third quarter of 2020, we sold VALARIS 8500, VALARIS 8501 and VALARIS 8502 for a total pre-tax gain of $7.7 million, we sold the VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6 for an insignificant pre-tax loss and we classified VALARIS 8504 as held-for-sale. The net book value of VALARIS 8504 did not exceed the fair value less costs to sell; therefore, we did not recognize an impairment upon classifying this rig as held-for-sale. The rig was subsequently sold in October 2020. 68 There are approximately 25 newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 10 are scheduled to be delivered before the end of 2021. Most newbuild floaters are uncontracted. Several newbuild deliveries have been delayed into future years, and we expect that more uncontracted newbuilds will be delayed or cancelled. Drilling contractors have retired approximately 160 floaters since the beginning of 2014. Approximately 15 floaters older than 30 years of age are currently idle, approximately ten additional floaters older than 30 years of age have contracts that will expire by the end of 2021 without follow-on work. Additional rigs are expected to become idle as a result of market conditions. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify these aging rigs may prove cost prohibitive. Drilling contractors will likely elect to scrap or cold-stack some or all of these rigs. Improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized. Jackups During 2020, demand for jackups has declined in light of increased market uncertainty. We have received notices of termination, requests for concessions, cancellation and/or deferral of drilling programs by operators, and we may receive additional requests for concessions, termination and/or deferral notices during the pendency of the current market environment. During the first quarter of 2020, we executed a three-well contract for VALARIS JU-118 that commenced in mid-March 2020 with an estimated duration of 425 days. Additionally, we executed a two-well contract for VALARIS JU-144 that commenced in May 2020 with an estimated duration of 300 days. The previously disclosed contract for the VALARIS JU-144 that was expected to commence in September 2020 was transferred to the VALARIS JU-102 and was subsequently delayed to September 2021, with VALARIS JU-102 being put on a standby rate until the new commencement date. VALARIS JU-87 was awarded a one-well contract that commenced in March 2020 with an estimated duration of 30 days and an extension to May 2020 for another well with an estimated duration of 30 days. During the first quarter of 2020, the VALARIS JU-109 contract was terminated. During the second quarter of 2020, the VALARIS JU-84 contract was terminated and we negotiated a day rate reduction for VALARIS JU-290 to be suspended at a reduced rate from September 2020 to February 2021. In April 2020, there were various negotiated customer contract concessions, including day rate reductions. VALARIS JU-120 was suspended at a reduced day rate from late-April 2020 to September 2020 and VALARIS JU-72 was suspended at a reduced day rate from April 2020 to August 2020. VALARIS JU-92 was previously expected to be suspended at a reduced day rate from mid-May 2020 to late-September 2020, but has continued to operate at full day rate. VALARIS JU-249 ended its contract in April 2020 and VALARIS JU-100 ended its contract in late-April 2020, in both cases, earlier than expected. During the second quarter of 2020, we executed short-term contracts for VALARIS JU-102 and VALARIS JU-87 that commenced in June 2020 and May 2020, respectively. We were also awarded a two-well extension for VALARIS JU-291 with an expected duration of approximately 230 days from January 2021 to August 2021. We executed a four-year contract for VALARIS JU-104 expected to commence in September 2020, which was subsequently terminated during the third quarter of 2020. Additionally, we extended the VALARIS JU-67 contract 210 days from May 2020 to December 2020. During the third quarter of 2020, VALARIS JU-54 and VALARIS JU-76 were put on a reduced standby rate until late 2020. Following the reduced standby rate period, VALARIS JU-54 will be operating at an agreed upon reduced day rate until the end of 2021 and VALARIS JU-76 will be suspended until it resumes operation in March 2021 at an agreed upon reduced day rate until the end of 2021. During the third quarter, we also negotiated reduced rates for VALARIS 108, VALARIS 140 and VALARIS 141. The reduced rates are effective beginning the second quarter of 2020 through the end of their contract terms in November 2021, June 2021 and August 2021, respectively. Additionally, we executed a one year contract extension for VALARIS 110 that commenced in October 2020 and executed a short-term contract for VALARIS 115 that commenced in February 2021. 69 During the fourth quarter of 2020, we executed an eight-well contract extension for VALARIS JU-292 Additionally, we extended the VALARIS JU-67 contract for approximately 190 days from December 2020 to June 2021. In January and February 2021, we executed a two-year contract for VALARIS JU-121, an approximate one-year contract for VALARIS JU-247, and the VALARIS JU-122 contract was extended for approximately 95 days from April 2021 to July 2021. Our backlog for our jackup segment was $859.5 million and $1,281.2 million as of December 31, 2020 and December 31, 2019, 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. The VALARIS JU-68 was sold in January 2020, resulting in an insignificant pre-tax gain. Additionally, VALARIS JU-70 and VALARIS JU-71 were sold in June 2020 resulting in insignificant pre-tax losses. During the second quarter of 2020, we classified VALARIS JU-105 as held-for-sale, resulting in an insignificant impairment as the net book value exceeded the fair value less cost to sell. During the third quarter of 2020, we sold VALARIS JU-87 and VALARIS JU-105 for an insignificant pre-tax gain and we classified VALARIS JU-84 and VALARIS JU-88 as held-for-sale. The net book values of VALARIS JU-84 and VALARIS JU-88 did not exceed the fair values less costs to sell, therefore, we did not recognize an impairment upon classifying these rigs as held-for-sale. These rigs were subsequently sold in October 2020. There are approximately 40 newbuild jackup rigs reported to be under construction, of which 20 are scheduled to be delivered before the end of 2021. 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 approximately 120 jackups since the beginning of 2014. Approximately 90 jackups older than 30 years of age are currently idle and 40 jackups that are 30 years of age or older have contracts expiring by the end of 2021 without follow-on work. Expenditures required to re-certify these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs. Improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized. 70 RESULTS OF OPERATIONS The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2020 (in millions): 2020 2019 2018 Revenues $ 1,427.2 $ 2,053.2 $ 1,705.4 Operating expenses Contract drilling (exclusive of depreciation) 1,458.6 1,806.0 1,319.4 Loss on impairment 3,646.2 104.0 40.3 Depreciation 540.8 609.7 478.9 General and administrative 214.6 188.9 102.7 Total operating expenses 5,860.2 2,708.6 1,941.3 Other operating income 118.1 — — Equity in losses of ARO (7.8) (12.6) — Operating loss (4,322.7) (668.0) (235.9) Other income (expense), net (794.3) 604.2 (303.0) Provision (benefit) for income taxes (259.4) 128.4 89.6 Loss from continuing operations (4,857.6) (192.2) (628.5) Loss from discontinued operations, net — — (8.1) Net loss (4,857.6) (192.2) (636.6) Net (income) loss attributable to noncontrolling interests 2.1 (5.8) (3.1) Net loss attributable to Valaris $ (4,855.5) $ (198.0) $ (639.7) Overview Year Ended December 31, 2020 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 JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88, and VALARIS JU-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 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 5 - 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 $347.4 million, or 19%, as compared to the prior year primarily due to a $184.4 million decline as a result of lower costs on idle rigs, $134.5 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 JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-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 71 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 first and second quarters of 2020, 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 7 - 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 period 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 JU-123 which commenced operations in August 2019. General and administrative expenses increased by $25.7 million, or 14%, as compared to the prior year period 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 period, 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 $140.7 million as we discontinued accruing interest on our outstanding debt subsequent to the chapter 11 filing. Year Ended December 31, 2019 Revenues increased by $347.8 million, or 20%, as compared to the prior year primarily due to $322.2 million of revenue earned by the Rowan rigs, $125.5 million due to revenues earned from our rigs leased to ARO and revenues earned from the Secondment Agreement and Transition Services Agreement, and $84.1 million due to the commencement of VALARIS DS-9, VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 6001, VALARIS 5006 and ENSCO 97, which operated in the prior-year period, and lower average day rates across the remaining fleet. Contract drilling expense increased by $486.6 million, or 37%, as compared to the prior year primarily due to $351.2 million of contract drilling expense incurred by the Rowan rigs, $57.0 million due to expenses incurred under the Secondment Agreement and by our rigs leased to ARO, $38.2 million due to the commencement of VALARIS DS-9, and $31.3 million due to the commencement of drilling operations for VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141. This increase was partially offset by the sale of ENSCO 6001, VALARIS 5006 and ENSCO 97, which operated in the prior-year period. General and administrative expenses increased by $86.2 million, or 84%, as compared to the prior year, primarily due to transaction and integration costs associated with the Rowan Transaction. 72 Rig Counts, Utilization and Average Day Rates The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction, rigs held-for-sale and ARO's offshore drilling rigs as of December 31, 2020, 2019 and 2018. Legacy Rowan and ARO rigs are included from the date the Rowan Transaction closed in April 2019: 2020 2019 2018 Floaters (1) 16 24 22 Jackups (2) 36 41 34 Other (3) 9 9 — Held-for-sale (4) — 3 — Total Valaris 61 77 56 Valaris - Under construction (5) 2 2 3 ARO (6) 7 7 — ARO - Under construction (7) 2 — — (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. During 2019, we added VALARIS DS-15, VALARIS DS-16, VALARIS DS-17 and VALARIS DS-18 from the Rowan Transaction, sold VALARIS 5006 and classified VALARIS 6002 as held-for-sale (2) During 2020, we sold VALARIS JU-71, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-105. During 2019, we added 10 jackups from the Rowan Transaction, exclusive of rigs leased to ARO that are included in Other, accepted delivery of VALARIS JU-123, classified VALARIS JU-68 and VALARIS JU-70 as held-for-sale and sold VALARIS JU-96 and ENSCO 97. (3) During 2019, we added nine jackups from the Rowan Transaction that are leased to ARO. (4) During 2019, we classified VALARIS JU-68, VALARIS JU-70 and VALARIS 6002 as held-for-sale, all of which were subsequently sold in 2020. (5) During 2019, we accepted the delivery of VALARIS JU-123. (6) This represents the seven rigs owned by ARO. (7) During 2020, ARO ordered two newbuild jackup rigs scheduled for delivery in 2022. 73 The following table summarizes our and ARO's rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2020. 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: 2020 2019 2018 Rig Utilization (1) Floaters 29% 47% 46% Jackups 54% 66% 63% Other (2) 98% 100% 100% Total Valaris 54% 63% 56% ARO 94% 93% —% Average Day Rates (3) Floaters $ 178,372 $ 218,837 $ 248,395 Jackups 83,618 78,133 77,086 Other (2) 31,207 49,236 81,751 Total Valaris $ 83,845 $ 108,313 $ 128,365 ARO $ 100,921 $ 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. 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. 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 nine 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 and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations and shipyard contracts. Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below. 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. 74 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. 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. See " Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements. 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. 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. See " Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements. Segment information for each of the years in the three-year period ended December 31, 2020 is presented below (in millions). Year Ended December 31, 2020 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) 633.9 733.3 388.2 91.4 (388.2) 1,458.6 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) $ (3,659.0) $ (439.5) $ 82.2 $ 14.2 $ (320.6) $ (4,322.7) 75 Year Ended December 31, 2019 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) 898.6 788.9 280.2 118.5 (280.2) 1,806.0 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) $ (334.7) $ (167.8) $ 62.9 $ 60.2 $ (288.6) $ (668.0) Year Ended December 31, 2018 Floaters Jackups ARO Other Reconciling Items Consolidated Total Revenues $ 1,013.5 $ 630.9 $ — $ 61.0 $ — $ 1,705.4 Operating expenses Contract drilling (exclusive of depreciation) 737.4 526.5 — 55.5 — 1,319.4 Loss on impairment — 40.3 — — — 40.3 Depreciation 311.8 153.3 — — 13.8 478.9 General and administrative — — — — 102.7 102.7 Operating income (loss) $ (35.7) $ (89.2) $ — $ 5.5 $ (116.5) $ (235.9) Floaters 2020 compared to 2019 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 $264.7 million, or 29%, as compared to the prior year primarily due to $131.1 million lower cost on idle rigs, $92.3 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 7 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. 76 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. 2019 compared to 2018 During 2019, revenues were consistent with the prior year. The $109.3 million of revenue earned by the Rowan rigs and $41.0 million due to the commencement of VALARIS DS-9 drilling operations were offset by the sale of VALARIS 5006 and ENSCO 6001, fewer days under contract and lower average day rates across the remaining floater fleet. Contract drilling expense increased by $161.2 million, or 22%, as compared to the prior year primarily due to $142.4 million of contract drilling expense incurred by the Rowan rigs and $38.2 million due to the commencement of VALARIS DS-9 drilling operations. The increase was partially offset by the sale of VALARIS 5006 and ENSCO 6001 and lower costs on idle rigs. Depreciation expense increased by $50.5 million, or 16%, compared to the prior year primarily due to the addition of the Rowan rigs to the fleet and commencement of VALARIS DS-9 drilling operations. Jackups 2020 compared to 2019 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 JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88, and VALARIS JU-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 $55.6 million, or 7%, as compared to the prior year primarily due to $53.3 million lower cost on idle rigs, $42.2 million from the sale of VALARIS JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-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 7 - 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 the Rowan Transaction as well as the commencement of the VALARIS JU-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. 2019 compared to 2018 During 2019, revenues increased by $203.7 million, or 32%, as compared to the prior year primarily due to $212.9 million of revenue earned by the Rowan rigs and $43.1 million due to the commencement of VALARIS 77 JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80, which operated in the prior-year period. Contract drilling expense increased by $262.4 million, or 50%, as compared to the prior year primarily due to $208.8 million of contract drilling expense incurred by the Rowan rigs and $31.3 million due to the commencement of drilling operations for VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80. Depreciation expense increased by $50.0 million, or 33%, as compared to the prior year primarily due to the addition of rigs in the Rowan Transaction and the commencement of VALARIS JU-123 in August 2019. ARO ARO currently owns a fleet of seven jackup rigs, leases another nine 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 with delivery scheduled 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. 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. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. 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 rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO are under three-year contracts with Saudi Aramco. All seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco. The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for the seven ARO-own jackup rigs that operated during the period from the date of the Rowan Transaction in April 2019 through December 31, 2020. The contract drilling, depreciation and general and administrative expenses are also for the period from the date of the Rowan Transaction in April 2019 through December 31, 2020. 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. 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. 78 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 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO. Other 2020 compared to 2019 Other revenues declined $48.1 million, or 24%, for the year ended December 31, 2020, as compared to the prior year period, primarily due to 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 5 - 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 $27.1 million, or 23%, for the year ended December 31, 2020, as compared to the prior year period, 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 4 - 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 Bess Brants and Ernest Dees which were in the shipyard most of the comparative period. 2019 compared to 2018 Other revenues increased $143.2 million, or 235%, for the year ended December 31, 2019, as compared to the prior year period, primarily due to revenues earned from our rigs leased to ARO, revenues earned under the Secondment Agreement and Transition Services Agreement of $58.2 million, $49.9 million and $17.3 million, respectively. Other contract drilling expenses increased $63.0 million, or 114%, for the year ended December 31, 2019, respectively, as compared to the prior year period, primarily due to costs incurred for services provided to ARO under the Secondment Agreement and other costs for ARO rigs. 79 Impairment of Long-Lived Assets See " Note 4 - Rowan Transaction", " Note 7 - Property and Equipment" and " Note 15 - 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, for each of the years in the three-year period ended December 31, 2020 (in millions): 2020 2019 2018 Interest income $ 19.7 $ 28.1 $ 14.5 Interest expense, net: Interest expense (291.9) (449.2) (345.3) Capitalized interest 1.3 20.9 62.6 (290.6) (428.3) (282.7) Reorganization items, net (527.6) — — Other, net 4.2 1,004.4 (34.8) $ (794.3) $ 604.2 $ (303.0) Interest income decreased during 2020 as compared to the respective prior-year period primarily due to fewer investments in the current year as compared to the prior year comparable period. Interest income increased during 2019 as compared to the respective prior-year period primarily due to interest income of $16.8 million earned on the shareholder note from ARO (see " Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on ARO) acquired in the Rowan Transaction. Interest expense decreased during 2020 by $157.3 million, or 35%, as compared to the prior year as we did not accrue interest on our outstanding debt or amortize discounts, premiums and debt issuance costs subsequent to the chapter 11 filing totaling $140.7 million and $29.8 million, respectively. 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 increased during 2019 by $103.9 million, or 30%, as compared to the prior year due to interest expense incurred on senior notes acquired in the Rowan Transaction. Interest expense capitalized declined during 2020 and 2019 by $19.6 million, or 94%, and $41.7 million, or 67%, as compared to the prior year periods, due to a decline in the amount of capital invested in newbuild construction resulting from newbuild rigs being placed into service. Reorganization items, net of $527.6 million recognized during 2020 was related to other net losses and expenses directly related to 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 financing costs of $20.0 million, partially offset by $7.1 million of contract items relating to rejection and amendment of certain operating leases. Other, net, during 2020 included $14.6 million of net periodic income, excluding service cost, for our pension and retiree medical plans as well as a $3.1 million pre-tax gain on extinguishment of debt. We also incurred 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, during 2019 included a gain on bargain purchase recognized in connection with the Rowan Transaction of $630.7 million, a pre-tax gain related to the award related to settlement with Samsung Heavy 80 Industries of $200.0 million and a pre-tax gain from debt extinguishment of $194.1 million related to the senior notes repurchased in connection with our July 2019 tender offers. This increase was partially offset by settlement of a Middle East dispute discussed in " Note 14 - Commitments and Contingencies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" as well as foreign currency losses as 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 losses, inclusive of offsetting fair value derivatives, were $11.0 million, $7.4 million and $17.2 million, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively. Net foreign currency exchange losses incurred during 2020 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. During 2018, the net foreign currency exchange losses incurred included $5.8 million, $3.6 million and $2.0 million, related to Angolan kwanza, euros and Brazilian reals, respectively. Net unrealized gains of $3.2 million and $5.0 million and unrealized losses of $0.7 million from marketable securities held in our supplemental executive retirement plans ("the SERP") were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively. Information on the fair value measurement of our marketable securities held in the SERP is presented in " Note 6 - Fair Value Measurements" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Provision for Income Taxes Valaris plc, our parent company, is domiciled and resident in the U.K. 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-U.K. subsidiaries is generally not subject to U.K. taxation. 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. 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. In periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Further, we may continue to incur income tax expense in periods in which we operate at a loss. 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. During 2018, we recognized a tax benefit of $11.7 million associated with the one-time transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries. 81 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 year ended December 31, 2020, we recorded an income tax benefit of $259.4 million and during the years ended December 31, 2019 and 2018 we recorded income tax expense of $128.4 million and $89.6 million, respectively. Our consolidated effective income tax rates during the same periods were 5.1%, (201.3)% and (16.6)%, respectively. 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 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. Our 2018 consolidated effective income tax rate includes the impact of various discrete tax items, including $46.0 million of tax benefit associated with the utilization of foreign tax credits subject to a valuation allowance, the transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries, and a restructuring transaction, partially offset by $21.0 million of tax expense related to recovery of certain costs associated with an ongoing legal matter, repurchase and redemption of senior notes, unrecognized tax benefits associated with tax positions taken in prior years and rig sales. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020, 2019 and 2018 were (7.6)%, (14.6)% and (24.8)%, 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 14 jackup rigs, seven dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and three drillships during the three-year period ended December 31, 2020. 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 DIP Credit Agreement, 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 older, lower-specification or non-core rigs. 82 We sold the following rigs during the three-year period ended December 31, 2020 (in millions): Rig Date of Sale Classification (1) Segment (1) Net Proceeds Net Book Value (2) Pre-tax Gain/(Loss) VALARIS 8504 October 2020 Continuing Floater $ 4.7 $ 4.0 $ .7 VALARIS JU-88 October 2020 Continuing Jackups 1.4 .3 1.1 VALARIS JU-84 October 2020 Continuing Jackups 1.2 .3 .9 VALARIS JU-105 September 2020 Continuing Jackups 2.1 .8 1.3 VALARIS DS-6 August 2020 Continuing Floaters 5.7 6.1 (.4) VALARIS JU-87 August 2020 Continuing Jackups .3 .2 .1 VALARIS 8500 July 2020 Continuing Floaters 4.0 .7 3.3 VALARIS 8501 July 2020 Continuing Floaters 4.0 .7 3.3 VALARIS 8502 July 2020 Continuing Floaters 1.8 .7 1.1 VALARIS DS-3 July 2020 Continuing Floaters 6.1 6.1 — VALARIS DS-5 July 2020 Continuing Floaters 6.1 6.1 — VALARIS JU-71 June 2020 Continuing Jackups .2 .8 (.6) VALARIS JU-70 June 2020 Continuing Jackups .6 1.0 (.4) VALARIS 5004 April 2020 Continuing Floaters 1.9 2.0 (.1) VALARIS JU-68 January 2020 Continuing Jackups .3 .3 — VALARIS 6002 January 2020 Continuing Floaters 2.1 .9 1.2 VALARIS JU-96 December 2019 Continuing Jackups 1.9 .3 1.6 VALARIS 5006 November 2019 Continuing Floaters 7.0 6.0 1.0 VALARIS JU-42 October 2019 Continuing Jackups 2.9 2.5 .4 Gorilla IV May 2019 Continuing Jackups 2.5 2.5 — ENSCO 97 April 2019 Continuing Jackups 1.7 1.0 .7 ENSCO 80 August 2018 Continuing Jackups 1.0 .5 .5 ENSCO 5005 August 2018 Continuing Floaters 4.0 2.0 2.0 ENSCO 6001 July 2018 Continuing Floaters 2.0 .9 1.1 ENSCO 7500 April 2018 Discontinued Floaters 2.6 1.5 1.1 ENSCO 81 April 2018 Continuing Jackups 1.0 .3 .7 ENSCO 82 April 2018 Continuing Jackups 1.0 .3 .7 $ 70.1 $ 48.8 $ 21.3 (1) Classification denotes the location of the operating results and gain (loss) on sale for each rig in our consolidated statements of operations. For rigs' operating results that were reclassified to discontinued operations in our consolidated statements of operations, these results were previously included within the specified operating segment. (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 Chapter 11 Cases and Effect of Automatic Stay On August 19, 2020, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court and subsequently obtained joint administration of the Chapter 11 Cases under the caption In re Valaris plc, et al. , Case No. 20-34114 (MI). Any efforts to enforce payment obligations 83 related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On August 18, 2020, the Debtors entered into the Original RSA with the Consenting Noteholders. On February 5, 2021, the Debtors entered into the Amended RSA with the Consenting Noteholders and the Consenting Lenders. The Amended RSA contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. The Amended RSA also provides for certain conditions to the obligations of the parties and for termination upon the occurrence of certain events, including without limitation, the failure to achieve certain milestones and certain breaches by the parties under the Amended RSA. Subject to certain exceptions, under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Chapter 11 Cases. Notwithstanding the general applicability of the automatic stay described above, governmental authorities may determine to continue actions brought under their regulatory powers. Although Valaris intends to pursue the restructuring in accordance with the terms set forth in the Amended RSA, there can be no assurance that Valaris will be successful in completing a restructuring or any other similar transaction on the terms set forth in the Amended RSA, on different terms or at all. Among other things, the Amended RSA includes an outside date milestone requiring the Company’s emergence from chapter 11 by no later than June 15, 2021 (subject to a potential 60-day extension pursuant to the terms of the Amended RSA). The Debtors continue to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of the Chapter 11 Cases, the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption. In addition, we have obtained a DIP Facility to fund operations during the bankruptcy proceedings. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. There can be no assurance that we will confirm and consummate a plan of reorganization as contemplated by the Amended RSA or complete another plan of reorganization with respect to the Chapter 11 Cases and as such, there is substantial doubt about our ability to continue as a going concern. Further, we have concluded that management’s plans do not alleviate the substantial doubt about our ability to continue as a going concern brought about by the significant risks and uncertainties related to our liquidity and Chapter 11 Cases for a period of one year after the date that the financial statements are issued. 84 Liquidity Our liquidity position as of December 31, 2020, 2019 and 2018 is summarized below (in millions, except ratios): 2020 2019 2018 Cash and cash equivalents $ 325.8 $ 97.2 $ 275.1 Short-term investments — — 329.0 Available DIP Facility capacity 500.0 — — Available credit facility borrowing capacity — 1,622.2 2,000.0 Total liquidity $ 825.8 $ 1,719.4 $ 2,604.1 Working capital $ 746.1 $ 233.7 $ 781.2 Current ratio (1) 2.7 1.3 2.5 (1) As a result of our chapter 11 filing, we reclassified $7.3 billion representing the principal balance on our unsecured Senior Notes (as defined below), the amount of outstanding borrowings on our revolving credit facility, the accrued interest on our senior notes and revolving credit facility, and rig holding costs for DS-13 and DS-14 to “Liabilities Subject to Compromise” as of December 31, 2020. The current ratio calculated above does not reflect our debt and related interest that would otherwise be current but is stayed under our Chapter 11 Cases, nor does it include rig holding costs for VALARIS DS-13 and VALARIS DS-14. Cash and Debt As discussed in " Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on Chapter 11 Cases and above, we have filed the Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness. The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes and revolving credit facility. Any efforts to enforce payment obligations under the Senior 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, and revolving credit facility are automatically stayed as a result of the filing of the Chapter 11 Cases. The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as $581.0 million outstanding borrowings under our revolving credit facility as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. On September 2 5, 2020, we entered into the $500.0 million DIP Facility to provide liquidity during the pendency of the Chapter 11 Cases and expect exit financing in the form of a fully backstopped rights offering to noteholders for $550 million of New Secured Notes. We expect the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases. Additionally, we expect the exit financing to include the backstopped New Secured Notes and that these notes will provide the necessary liquidity to support ongoing operations and working capital needs. The maturity date of the DIP Credit Agreement is the earliest of (1) August 17, 2021, (2) acceleration of the loans under the DIP Facility and termination of the lenders' commitments under the DIP Facility, (3) the substantial consummation of any plan filed in the Chapter 11 Cases that is confirmed pursuant to an order entered by the Bankruptcy Court and (4) the consummation of a sale of all or substantially all of the assets of the Company and the other Debtors under section 363 of the Bankruptcy Code. Loans under the DIP Credit Agreement accrue interest at a rate of 8.00% per annum, if paid in kind, and at a rate of 7.00% per annum, if paid in cash. 85 The DIP Credit Agreement contains a requirement that the Company and any other borrowers provide every four weeks, a rolling 13 week budget to be approved by the required lenders (the “Approved Budget”). The Company and any other borrower that becomes party to the DIP Credit Agreement may not vary from the Approved Budget by more than 15% of the forecasted amounts in any forecast period. The Approved Budget is, subject to certain exceptions and is tested at certain times in accordance with the DIP Credit Agreement in order to measure variances between the actual total cash disbursements (excluding professional fees and certain other items consistent with the initial Approved Budget) and the disbursements budgeted for the applicable period. As of December 31, 2020, there were no borrowings outstanding under the DIP Credit Agreement. The DIP Credit Agreement does not provide for the issuance of letters of credit but permits occurrence of letters of credit in certain circumstances. Any proceeds of the loans under the DIP Credit Agreement may be used (1) to provide working capital to the borrowers and their subsidiaries and for other general corporate purposes in accordance with the rolling 13 week budget to be approved by the required lenders every four weeks (subject to the Permitted Variance), (2) to pay interest, fees, costs and expenses related to the DIP Facility, (3) to pay fees, costs and expenses of the estate professionals retained for the Chapter 11 Cases as approved by the Bankruptcy Court and as provided for in the Approved Budget (subject to the Permitted Variance), (4) make all permitted payments of costs of administration of the Chapter 11 Cases, (5) pay pre-petition expenses as are consistent with the Approved Budget (subject to the Permitted Variance) and approved by the Bankruptcy Court, (6) to fund the reasonable activities, costs and fees in respect of any insolvency proceedings in the United Kingdom and (7) make other payments permitted by the applicable Approved Budget. The DIP Credit Agreement contains events of default customary to debtor-in-possession financings, including events related to the Chapter 11 Cases, the occurrence of which could result in the acceleration of the Debtors’ obligation to repay the outstanding indebtedness under the DIP Credit Agreement. The Debtors’ obligations under the DIP Credit Agreement are secured by a security interest in, and lien on, substantially all present and after acquired property (subject to certain exceptions) of the Debtors and are guaranteed by certain of the Company’s subsidiaries, including other Debtors. The DIP Credit Agreement also contains customary covenants that limit the ability of the Company and its subsidiaries to, among other things, (1) incur additional indebtedness and permit liens to exist on their assets, (2) pay dividends or make certain other restricted payments, (3) sell assets and (4) make certain investments. These covenants are subject to exceptions and qualifications as set forth in the DIP Credit Agreement. During the three-year period ended December 31, 2020, our primary sources of cash were $1.0 billion in proceeds from issuance of senior notes, Rowan cash acquired of $931.9 million, $581.0 million in net borrowings under our revolving credit facility and $440.0 million from short-term investments, net. While the revolving credit facility has not been terminated, no further borrowings are permitted. Our primary uses of cash for the same period were $1.7 billion for the repurchase and redemption of outstanding debt, $747.5 million for the construction, enhancement and other improvements of our drilling rigs and $584.3 million used in operating activities. Cash Flows and Capital Expenditures Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2020 were as follows (in millions): 2020 2019 2018 Net cash used in operating activities of continuing operations $ (251.7) $ (276.9) $ (55.7) Capital expenditures $ 93.8 $ 227.0 $ 426.7 During 2020, 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. 86 During 2019, cash flows from continuing operations declined by $221.2 million as compared to the prior year due primarily to costs incurred related to the Rowan Transaction, interest on the debt assumed in the Rowan Transaction and declining margins. Based on our current projections, we expect capital expenditures during 2021 to approximate $42.5 million for rig enhancement projects and minor upgrades and improvements. Depending on market conditions and opportunities, we may reduce our planned expenditures or make additional capital expenditures to upgrade rigs for customer requirements. Financing and Capital Resources Debt to Capital Our total debt, total capital and total debt to total capital ratio as of December 31, 2019 were $6.5 billion, $15.8 billion and 41.2%, respectively. Our total debt, total capital and total debt to total capital ratio as of December 31, 2018 were $5.2 billion, $13.3 billion and 38.9%, respectively. Total debt consisted of the principal amount outstanding and total capital consisted of total debt and Valaris shareholders' equity. During 2020, our total debt principal increased by $568.2 million primarily as a result of borrowings on our revolving credit facility and total capital declined by $4.4 billion primarily due to operating losses, inclusive of impairment of long-lived assets. During 2019, our total debt principal increased by $1.4 billion and total capital increased by $2.6 billion as a result of the debt acquired and equity issued in connection with the Rowan Transactions. See " No te 4 - Rowan Transaction" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data". During 2020, we paid $23.8 million of fees related to the establishment of the DIP Credit Agreement, with $20.0 million of these fees included in Reorganization items, net on the Consolidated Statement of Operations for the year ended December 31, 2020. As of December 31, 2020, we were in compliance with our covenants under the DIP Credit Agreement. The commencement of the Chapter 11 Cases resulted in 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 have been automatically stayed as a result of the filing of the Chapter 11 Cases. Pursuant to the plan of reorganization contemplated by the Amended RSA, each series of our Senior Notes will be cancelled and the holders thereunder will receive the treatment as set forth in the plan of reorganization. Accordingly, the $6.5 billion in aggregate principal amount under the Senior Notes are Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. Senior Notes 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 have been repaid in full, (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. 87 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 is 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 is 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 is payable semiannually on March 15 and September 15 of each year. Interest on the New 2044 Notes is 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 is payable semiannually on April 1 and October 1 of each year. The Existing 2044 Notes together with the New 2044 Notes, the "2044 Notes", are 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 is 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 has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. Certain of these senior notes allow us to redeem these senior notes, either in whole in part, subject to the payment of certain “make whole” premiums. However, due to the commencement of the Chapter 11 Cases, we do not expect to make any such redemptions. The indentures governing these senior notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contains 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. 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 is 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 contain customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The 88 indenture also contains 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. 2024 Convertible Notes I n 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 our debt agreement, we have 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, are automatically stayed as a result of the filing of the Chapter 11 Cases. Interest on the 2024 Convertible Notes is 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 is 17.8336 shares per $1,000 principal amount of notes, representing an exchange price of $56.08 per share, and is 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 indenture governing the 2024 Convertible Notes contains customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contains 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. See " Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes. The 2021 Notes, 4.875% 2022 Notes, 4.75% 2024 Notes, 8% 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". The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes. See " Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information related to our Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness. Tender Offers and Open Market Repurchases 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 Ensco International Incorporated and RCI, 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. 89 Concurrent with the issuance of the 2026 Notes in January 2018, we launched cash tender offers for up to $985.0 million aggregate principal amount of certain series of senior notes issued by us and Pride, our wholly-owned subsidiary, and as a result we repurchased $595.4 million of our senior notes. Subsequently, we issued a redemption notice for the remaining principal amount of the $55.0 million principal amount of the 8.50% senior notes due 2019 and repurchased $71.4 million principal amount of our senior notes due 2020. As a result of these transactions, we recognized a pre-tax loss from debt extinguishment of $19.0 million, net of discounts, premiums, debt issuance costs and commissions. Our tender offers and open market repurchases during the three-year period ended December 31, 2020 are summarized in the following table (in millions): 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 Year Ended December 31, 2018 8.50% Senior notes due 2019 $ 237.6 $ 256.8 6.875% Senior notes due 2020 328.0 354.7 4.70% Senior notes due 2021 156.2 159.7 $ 721.8 $ 771.2 (1) Excludes accrued interest paid to holders of the repurchased senior notes. Revolving Credit Facility and DIP Facility Effective upon closing of the Rowan Transaction, our revolving credit facility was $1.6 billion. As previously disclosed, prior to the commencement of the Chapter 11 Cases, we entered into a series of waiver agreements (the “Waivers”) between the dates of June 1, 2020 and August 3, 2020 in respect of the revolving credit facility. The Waivers did not address any event of default resulting under the revolving credit facility attributed to the filing of Chapter 11 Cases. Consequently, the principal and interest under our revolving credit facility became immediately due and payable upon filing of such Chapter 11 Cases, which constituted an event of default under the revolving credit facility. However, the ability of the lenders under the revolving credit facility to exercise remedies in respect of the revolving credit facility was stayed upon commencement of the Chapter 11 Cases. While the revolving credit facility has not been terminated, notwithstanding the $1.6 billion borrowing capacity under the revolving credit facility, no further borrowings under the revolving credit facility are permitted. 90 As of December 31, 2020 , we had $581.0 million of borrowings outstanding under our revolving credit facility and $27.0 million of undrawn letters of cred it. The outstanding borrowings as well as accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. See " Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information related to our Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness. We expect cash on hand and the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases based on current projections of cash flows. Should we experience material variations from our projected cash flows, this could result in us having insufficient liquidity from the DIP Facility and in turn could have a material adverse impact on our financial position, operating results or cash flows. Maturities The original principal amounts issued under our senior notes have subsequently changed as a result of our tenders, repurchases, exchanges, redemptions and new debt issuances such that the balance outstanding at December 31, 2020 were as follows (in millions): Subject to Compromise (2) Senior Notes (2) Original Principal 2016 Tenders, Repurchases and Equity Exchange 2017 Exchange Offers and Repurchases 2018 Tender Offers, Redemption and Debt Issuance 2019 Tender Offers and Acquired Debt 2020 Open Market Repurchase Remaining Principal 6.875% Senior notes due 2020 $ 900.0 $ (219.2) $ (229.9) $ (328.0) $ — $ — $ 122.9 4.70% Senior notes due 2021 1,500.0 (817.0) (413.3) (156.2) — (12.8) 100.7 4.875% Senior notes due 2022 (1) — — — — 620.8 — 620.8 3.00% Exchangeable senior notes due 2024 849.5 — — — — — 849.5 4.50% Senior notes due 2024 625.0 (1.6) — — (320.0) — 303.4 4.75% Senior notes due 2024 (1) — — — — 318.6 — 318.6 8.00% Senior notes due 2024 — — 332.0 — (39.7) — 292.3 5.20% Senior notes due 2025 700.0 (30.8) — — (335.5) — 333.7 7.375% Senior notes due 2025 (1) — — — — 360.8 — 360.8 7.75% Senior notes due 2026 — — — 1,000.0 — — 1,000.0 7.20% Debentures due 2027 150.0 — — — (37.9) — 112.1 7.875% Senior notes due 2040 300.0 — — — — 300.0 5.40% Senior notes due 2042 (1) — — — — 400.0 — 400.0 5.75% Senior notes due 2044 1,025.0 (24.5) — — — — 1,000.5 5.85% Senior notes due 2044 (1) — — — — 400.0 — 400.0 Total $ 6,049.5 $ (1,093.1) $ (311.2) $ 515.8 $ 1,367.1 $ (12.8) $ 6,515.3 91 (1) These senior notes were acquired in the Rowan Transaction. (2) The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as associated $201.9 million in accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. The maturity dates represent the maturity dates per the debt agreements; however, we are in default on these senior notes and are currently in chapter 11 proceedings. See "Senior Notes" above and “ Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” included in "Item 8. Financial Statements and Supplementary Data" for additional information for additional details regarding Chapter 11 Cases. Other Financing Arrangements During 2018, our shareholders approved our current share repurchase program. Subject to certain provisions under English law, including the requirement of the Company to have sufficient distributable reserves and the Board to conclude that a repurchase is in the best interests of Valaris plc taking into account the interests of relevant stakeholders, we may repurchase shares up to a maximum of $500 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates in May 2023. As of December 31, 2020, there had been no share repurchases under this program. Our DIP Credit Agreement only permits the repurchase of our shares in certain limited circumstances and the repurchase of shares would likely require approval of the bankruptcy court. We do not currently expect to make repurchases under the program whilst Valaris plc remains subject to Chapter 11 bankruptcy proceedings. 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, earn interest at LIBOR plus two percent and 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 notes receivable may be reduced by future Company obligations to the joint venture. The distribution of earnings to the joint-venture partners is at the discretion of the ARO Board of Managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and long-term capital requirements of ARO. ARO has not made a cash distribution of earnings to its partners since its formation. See " Note 5 - Equity Method Investment in ARO" 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, 2020 (in millions): Maturity Date Principal amount October 2027 $ 265.0 October 2028 177.7 Total $ 442.7 92 Contractual Obligations We have various contractual commitments related to our rig construction agreements, long-term debt and operating leases. In light of our ongoing Chapter 11 Cases, our expectations with regards to settling these obligations may change. Generally, we expect to fund our commitments from existing cash and funds borrowed under our DIP Facility or other future financing arrangements unless otherwise stipulated in the Amended RSA. The following table summarizes our significant contractual obligations as of December 31, 2020 and the periods in which such obligations are due (in millions): Payments due by period 2021 2022 and 2023 2024 and 2025 Thereafter Total Principal payments on long-term debt (1) $ — $ — $ — $ — $ — New rig construction agreements (2)(3) 83.9 165.0 — — 248.9 Operating leases 17.8 15.0 4.2 9.0 46.0 Total contractual obligations (4) $ 101.7 $ 180.0 $ 4.2 $ 9.0 $ 294.9 (1) As a result of our chapter 11 filing, we reclassified $7.1 billion representing the principal balance on our unsecured senior notes and the amount of outstanding borrowings on our revolving credit facility to Liabilities Subject to Compromise on our Consolidated Balance Sheet as of December 31, 2020 . (2) As of December 31, 2020, the contractual delivery dates for the VALARIS DS-13 and VALARIS DS-14 were September 30, 2021 and June 30, 2022, respectively. The remaining milestone payments for VALARIS DS-13 and VALARIS DS-14 are included in the table above in the period in which they were contractually owed . The Amended RSA provides that on or before the effective date of the reorganization, the construction contracts for these rigs shall be rejected under Section 365 of the Bankruptcy Code, unless otherwise agreed between the shipyard and the Company with the consent of required consenting noteholders. If rejected, it is contemplated that we would have to pay an amount equal to the liquidation recovery, which is the amount the contract counterparty would be entitled to receive or retain if the applicable Company entity was liquidated under chapter 7 of the Bankruptcy Code. Prior to December 31, 2020, a Stipulation was filed with the Bankruptcy Court which included an Assumption Term Sheet stating amended terms of these construction agreements. Following further negotiations, we entered into amended agreements with the shipyard on February 26, 2021 that become 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 remove any Company guarantee. (3) Total commitments are based on fixed-price shipyard construction contracts, exclusive of our internal costs associated with project management, commissioning and systems integration testing. Total commitments also exclude holding costs and interest. (4) Contractual obligations do not include $286.1 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2020. We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts. In addition, we have a potential obligation to fund ARO for newbuild jackup rigs. In the event ARO has insufficient cash from 93 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. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. "See Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." for additional information on our joint venture with ARO. Other Commitments We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include 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. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2020, we had insignificant collateral deposits with respect to these agreements. The following table summarizes our other commitments as of December 31, 2020 (in millions): Commitment expiration by period 2021 2022 and 2023 2024 and 2025 Thereafter Total Letters of credit $ 88.5 $ 15.9 $ 7.2 $ 3.5 $ 115.1 Recent Tax Assessments During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $77.7 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 a $17.9 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2020. We believe our tax returns are materially correct as filed, and we are vigorously contesting these assessments. Although the outcome of such assessments and related administrative proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows. See " Note 13 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on recent tax assessments. 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 and, as of February 2019, had been ratified by 187 of the 197 parties to the United Nations Framework Convention on Climate Change, including the United Kingdom, the United States and the majority of the other countries in which we operate. 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 acting Secretary of the Department of the Interior recently issued 94 an order preventing staff from producing any new federal fossil fuel leases or permits without sign-off from a top political appointee. In addition, 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 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. The Companies Act 2006 (Strategic and Directors' Reports) Regulations 2013 now requires all quoted U.K. companies, including Valaris plc, to report their annual GHG emissions in the Company's directors' report. 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. These requirements for stationary sources took effect on January 2, 2011; however, in June 2014 the U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision upholding these rules and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement to obtain a federal air permit based solely on emissions of greenhouse gases. Large sources of other air pollutants, such as VOC or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding emissions of greenhouse gases. 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. 95 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. Our significant accounting policies are included in " Note 1 - Description of 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 long-lived assets, income taxes and pensions. Property and Equipment As of December 31, 2020, the carrying value of our property and equipment totaled $11.0 billion, which represented 85% 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. The judgments and assumptions used in determining the useful lives 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 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. During 2020, we recorded an aggregate pre-tax, non-cash impairment of $3.6 billion with respect to certain floaters, jackups and spare equipment. We estimate the portion of the aforementioned impairment related to 96 impaired rigs that remain in our fleet as of December 31, 2020 will cause a decline in depreciation expense of approximately $35.4 million for the year ended December 31, 2021. Our fleet of 16 floater rigs, excluding two rigs under construction, represented 54% of the gross cost and 55% of the net carrying amount of our depreciable property and equipment as of December 31, 2020. Our fleet of 36 jackup rigs, represented 37% of the gross cost and 36% of the net carrying amount of our depreciable property and equipment as of December 31, 2020. Our floater rigs and jackup rigs are depreciated over 35 and 30 years, respectively, for newly constructed assets and over their estimated remaining useful lives for rigs obtained in a business combination. The following table provides an analysis of estimated increases and decreases in depreciation expense from continuing operations that would have been recognized for the year ended December 31, 2020 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2020: Increase (decrease) in useful lives of our drilling rigs Estimated (decrease) increase in depreciation expense that would have been recognized (in millions) 10% $(41.5) 20% (76.1) (10%) 50.4 (20%) 101.5 Impairment of Property and Equipment We recorded pre-tax, non-cash losses on impairment of long-lived assets of $3.6 billion, $98.4 million and $40.3 million during 2020, 2019 and 2018, respectively. See " Note 7 - 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. 97 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. 98 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, 2020, our consolidated balance sheet included an $8.2 million net deferred income tax asset, a $33.9 million liability for income taxes currently payable and a $286.1 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. 99 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, 2020, included (1) a weighted average discount rate of 2.30% to determine pension benefit obligations, (2) a weighted average discount rate of 3.16% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.48% 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. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $125.6 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 $5.6 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which decreased to 6.03% at December 31, 2020 from 6.48% at December 31, 2019. See " Note 12 - Pension and Other Post Retirement Benefits" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on our pension and other postretirement benefit plans. NEW ACCOUNTING PRONOUNCEMENTS See " Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on new accounting pronouncements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Not applicable. 100 Item 8. Financial Statements and Supplementary Data MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2020 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. March 2, 2021 101 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Valaris plc: Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Valaris plc and subsidiaries (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three‑year period ended December 31, 2020 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, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2020, 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, 2020, 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 March 2, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company's operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 voluntary petition, that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. 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. 102 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. Impairment of property and equipment As discussed in Notes 1 and 7 to the consolidated financial statements, the Company recorded impairment with respect to certain floaters, jackups and spare equipment of $ 3.6 billion for the year ended December 31, 2020. On a quarterly basis, the Company evaluates the carrying value of property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. For property and equipment used in 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. To estimate the fair value of property and equipment, the Company utilized an income approach or estimated scrap value. We identified the evaluation of the impairment assessment for certain floaters and jackups as a critical audit matter. A high degree of subjective auditor judgment was required to evaluate certain inputs and assumptions used in the Company's recoverability assessment and determination of fair value using the income approach, specifically assumptions regarding future day rates, forecasted utilization and the discount rate. The assumptions related to future day rates and forecasted utilization were based on unobservable and subjective inputs for which there is limited information. Evaluation of the discount rate involved 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 Company's property and equipment impairment assessment process. This included controls over the determination of certain inputs and assumptions used in the recoverability assessment and the fair value estimates of floaters and jackups, including future day rates, forecasted utilization, and the discount rate. We evaluated the Company's estimated future day rates and forecasted utilization by comparing them to historical information, considering contract modifications and industry reports on floaters and jackups. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company's discount rate by comparing the Company's discount rate against discount rate ranges that we independently developed using publicly-available market data for comparable entities. Income tax positions pertaining to certain tax transactions As discussed in Notes 1 and 13 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 103 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 certain 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 March 2, 2021 104 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Valaris plc: Opinion on Internal Control Over Financial Reporting We have audited Valaris plc and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, 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, 2020, 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, 2020 and 2019, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated March 2, 2021 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 obtaini