POISED FOR GROWTH DIAMOND OFFSHORE Diamond Offshore is a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 14 offshore drilling rigs, consisting of four owned drillships, eight owned semi-submersible rigs and two managed rigs. Diamond Offshore’s headquarters are in Houston, Texas. Primary regional offices are located in Brazil, the United Kingdom and Australia, with local offices in other countries as required to support operations. Approximately 2,100 people work for the Company onboard our rigs and in our offices. Diamond Offshore’s common stock is listed on the New York Stock Exchange under the symbol “DO.” 2022 was a pivotal year for Diamond Offshore. We relisted on the New York Stock Exchange, secured $1.3 billion dollars in contract awards, including an award to reactivate the Ocean GreatWhite, and successfully started up two managed drillships, all while continuing to deliver industry-leading operational and safety excellence for our customers. Fueled by growth in global demand for energy and supply disruptions triggered by the war in Ukraine, activity in the offshore drilling market rebounded dramatically during 2022. After years of under-investment, in 2022 major oil companies pumped billions of dollars into offshore drilling, reversing a long decline in spending. During the recent downturn, our industry became more efficient, particularly with deepwater projects, which has reduced costs and significantly improved time to first oil. This efficiency, coupled with the fact that the carbon intensity of offshore production is frequently lower than that of onshore production, has incentivized our customers to allocate more capital to deepwater offshore which offers returns on investment that are in many cases superior to onshore projects. Industry sources predict that by 2030, due to favorable productivity and breakeven cost basis, investment in deepwater offshore drilling from 2022-2028 could lead to production volumes exceeding those of onshore and offshore shelf volumes combined. This recent recovery in activity and investments comes on the heels of eight years of lower rig utilization. During the downturn, Diamond Offshore and its industry contemporaries retired many rigs and limited investment in new build rigs. As a result of the constrained supply of rigs and increasing demand, Diamond was well-placed in a rapidly improving market to benefit from rising rig dayrates. A RISING TIDE Throughout 2022, market fundamentals continued to improve in our industry, driving improved dayrates and visibility of future demand. Growth in deepwater rig demand in both harsh and benign markets led to higher dayrates. For the floating rig fleet, which includes semi- submersibles and drillships, market utilization meaningfully improved during 2022. Drillship marketed utilization averaged 88% for the year, and average semi-submersible rig marketed utilization was 78%. At the same time, floating rig dayrates increased substantially, rising by an average of 58% and 30% for deepwater drillships and semi- submersibles respectively. These dayrate trends have shown no signs of reversing and create an opportunity for Diamond to benefit from the energy market resurgence. $1.8 BILLION BACKLOG Our commitment to our customers and to providing industry-leading operational excellence are the differentiators that drive return business and our strong contract backlog. This is part of the Diamond Difference™. During the year, Diamond added significant backlog, bringing the Company’s total contracted backlog to $1.8 billion at year-end, a sum which represents 17.6 rig years of future work for our Company. In 2022, Diamond was awarded contracts for the harsh environment semi-submersible Ocean GreatWhite in the U.K. North Sea (one of the most capable rigs of its type in the world), the semi-submersible Ocean Apex in Australia, and three 7th generation drillships—the Ocean Black- Hornet and two Diamond-managed rigs located in the U.S. Gulf of Mexico. In Brazil, we executed a new contract with Petrobras for the Ocean Courage. The four-year project, with an unpriced option for an additional four years, has a total firm term value of $429 million, including a mobilization fee and the provision of certain additional services. The contract is expected to begin late in the fourth quarter of 2023 after the conclusion of the rig’s current contract. These awards are a testament to the exceptional performance of our crews and enable Diamond to continue serving the world’s largest deepwater oil and gas companies. DIAMOND OFFSHORE Annual Report 2022 1 TO OUR SHAREHOLDERS (Dollars in millions) Revenue Depreciation & Amortization Operating Expenses Adjusted EBITDA Net (Loss) Capital Expenditures (2) Cash and Restricted Cash Drilling & Other Property & Equipment, Net Total Assets Debt Shareholders’ Equity 2022 $ 841 103 905 35 (103) 60 2021 (1) $ 725 161 1,204 6 (2,139) 92 2020 $ 734 320 1,887 19 (1,255) 190 $ 97 1,142 1,528 361 680 $ 63 1,176 1,531 266 768 $ 430 4,123 4,948 2,436 1,983 (1) Numbers presented reflect the combined results of the Successor and Predecessor Company as described in our Form 10-K filed February 28th, 2023. (2) Adjusted EBITDA is a financial measure that does not conform with generally accepted accounting principles in the United States (or GAAP). Please refer to the Diamond Offshore website at www.diamondoffshore.com for a reconciliation of GAAP to non-GAAP financial measures. REVENUE (Dollars in millions) ADJUSTED EBITDA (Dollars in millions) BACKLOG ADDED (Dollars in millions) $841 $35 $1,365 $734 $725 $19 $610 $6 $217 2020 2021 2022 2020 2021 2022 2020 2021 2022 2 FINANCIALHIGHLIGHTS REVENUE EFFICIENCY EXERCISING MARKET AND CAPITAL DISCIPLINE Despite the increased demand for drillships, we were selective in how we marketed our rigs and made prudent investment decisions. We main- tained a disciplined approach to capital expenditures and cold stacked two of our rigs with limited near-term demand. We continued to evaluate drilling contract opportunities for these rigs, but intend to only pursue projects that meet our internal hurdles for return on capital. RESPONSIBLY UNLOCKING ENERGY ESG is fundamental to our operations. In this vital area, we continued to focus on making our rigs more fuel efficient and reducing our carbon footprint. We recently analyzed historical fuel usage data for our four BlackShips, comparing closed-bus and open-bus electrical plant opera- tions. Closed-bus operations facilitate savings of up to 20% in fuel usage over comparable activities in an open bus configuration. All of Diamond’s large, dynamically-positioned rigs are equipped to support closed-bus operations. We continue to work closely with our clients to reduce fuel usage and greenhouse gas emissions. In 2023, we are committing resources to achieve ISO 50001 on three rigs, the Ocean GreatWhite, Ocean BlackHornet, and Ocean BlackLion. This should allow us to systematically identify ways to achieve and track our progress on emissions reductions. In addition, we are implementing a SaaS-enabled platform to enable emissions reduction through monitor- ing of real-time data. As part of our mission is to deliver fresh perspectives and solve complex deepwater challenges, we made discretionary investments in equipment to improve the safety and efficiency of our services. For example, in 2022 we sourced an MPD System for our Ocean BlackHawk drillship. MPD, or Managed Pressure Drilling, allows us to more efficiently drill wells while reducing the risks associated with wellbore pressure management. Subsea equipment repair and maintenance is a significant cause of nonproductive time across the offshore drilling industry. Our Stack-View service enables predictive maintenance and reduces downtime attributed to subsea equipment, thereby increasing drilling productivity and lowering the total cost of the well. The real-time data gathered and analyzed by Stack-View is continuously overlaid with historical data, then data visualization, trending, and advanced analytics are applied to predict when BOP components require preventive maintenance. This, coupled with our Sim-Stack® service, allows Diamond Offshore to continuously assess BOP status and assure regulatory compliance. These technologies led to the prevention of nine unplanned BOP pulls in 2022. Ocean BlackHornet, on location in the U.S. Gulf of Mexico. CONTRACTED BACKLOG DIAMOND OFFSHORE Annual Report 2022 3 $1.8B94% Drilling crew in cyber chairs testing drilling equipment for upcoming campaign in the North Sea. BETTER SAFETY PERFORMANCE THAN INDUSTRY A COMPREHENSIVE CULTURE OF SAFETY Our focus has always been to deliver best-in-class drilling performance while never compromising on safety performance. As an industry leader in health, safety, and environment, we believe that all incidents can be prevented by having the proper barriers, processes and procedures in place. Our strong safety performance in 2022 reflects those efforts, enabling us to achieve our best safety performance in the last four years. SHAREHOLDER ENGAGEMENT During the year we continued our long-standing, proactive shareholder engagement program to discuss recent market developments, gain investor perspective, and provide updates on our business. Since relisting, we have seen significant trading liquidity in our shares while adding over 150 institutional investors to our shareholder register. CONDITIONS IN PLACE FOR A NEW MULTI-YEAR UPCYCLE We believe marketed drillship supply and demand will remain tight in 2023 and utilization will continue at levels that have historically driven dayrates higher. As hydrocarbons are expected to remain the largest source of primary energy for years to come, we see sustained strength in offshore drilling and the foundation for a multi-year upcycle. In closing, I want to thank the employees at Diamond for their dedication and diligence, assuring that we are well-positioned to remain a leading provider of deepwater drilling services. This Diamond Difference is well established and continues to deliver value for our customers and shareholders. CONTRACT AWARDS Sincerely, Bernie Wolford, Jr. President and CEO, Diamond Offshore 4 50%12 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ☒☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2022 OR ☐☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-13926 DIAMOND OFFSHORE DRILLING, INC. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 76-0321760 (I.R.S. Employer Identification No.) 15415 Katy Freeway Houston, Texas 77094 (Address and zip code of principal executive offices) (281) 492-5300 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Exchange Act: Title of each class Common Stock, $0.0001 par value per share Trading Symbol DO Name of each exchange on which registered New York Stock Exchange Securities registered pursuant to Section 12(g) of the Exchange Act: None 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 during the preceding 12 ☐☑No months (or for such shorter period that the registrant was required to submit such files). Yes Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an 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 Non-accelerated filer Emerging growth company ☐ ☐ ☐ Accelerated filer Smaller reporting 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. ☑ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐ ☑No State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: As of June 30, 2022 $ 594,790,930 Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑No ☐ Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. As of February 22, 2023 Common Stock, $0.0001 par value per share 101,320,164 shares The information called for by Part III, Items 10, 11, 12, 13 and 14 of this Form 10-K, will be included in a definitive proxy statement or an amendment to this Form 10-K to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, and is incorporated herein by reference. DOCUMENTS INCORPORATED BY REFERENCE TABLE OF CONTENTS Cover Page................................................................................................................................................................................. Document Table of Contents.................................................................................................................................................... Part I Item 1. Item 1A. Item 1B. Item 2. Item 3. Item 4. Part II Item 5. Item 6. Item 7. Business................................................................................................................................................................ Risk Factors......................................................................................................................................................... Unresolved Staff Comments............................................................................................................................... Properties............................................................................................................................................................. Legal Proceedings ............................................................................................................................................... Mine Safety Disclosures...................................................................................................................................... Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ........................................................................................................................... [Reserved] ............................................................................................................................................................ Management’s Discussion and Analysis of Financial Condition and Results of Operations ........................................................................................................................................................... Item 7A. Quantitative and Qualitative Disclosures About Market Risk ....................................................................... Item 8. Financial Statements and Supplementary Data ............................................................................................... Consolidated Financial Statements.................................................................................................................... Notes to Consolidated Financial Statements..................................................................................................... Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................................................................................................................................. Controls and Procedures .................................................................................................................................... Other Information............................................................................................................................................... Disclosure Regarding Foreign Jurisdictions that Prevent Inspections........................................................... Directors, Executive Officers and Corporate Governance.............................................................................. Executive Compensation .................................................................................................................................... Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ........................................................................................................................................... Certain Relationships and Related Transactions, and Director Independence............................................. Principal Accounting Fees and Services............................................................................................................ Exhibits and Financial Statement Schedules .................................................................................................... Form 10-K Summary.......................................................................................................................................... Item 9. Item 9A. Item 9B. Item 9C. Part III Item 10. Item 11. Item 12. Item 13. Item 14. Part IV Item 15. Item 16. Signatures .................................................................................................................................................................................... Page No. 1 2 3 10 27 27 27 27 28 29 30 48 50 53 58 28 28 28 29 30 30 30 30 30 31 33 34 Item 1. Business. General PART I Diamond Offshore Drilling, Inc., incorporated in Delaware in 1989, provides contract drilling services to the energy industry around the globe with a fleet of 14 offshore drilling rigs, consisting of four owned drillships, eight owned semisubmersible rigs and two managed rigs. See “– Rig Management and Marketing Services” and “– Our Fleet – Fleet Status.” Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. Reorganization and Chapter 11 Proceedings On April 26, 2020 (or the Petition Date), Diamond Offshore Drilling, Inc. (or the Company) and certain of its direct and indirect subsidiaries (which we refer to, together with the Company, as the Debtors) commenced voluntary cases (or the Chapter 11 Cases) for relief under chapter 11 (or Chapter 11) of title 11 of the United States Code (or the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas (or the Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re Diamond Offshore Drilling, Inc., et al., Case No. 20-32307 (DRJ). On January 22, 2021, the Debtors entered into a Plan Support Agreement (or the PSA) among the Debtors, certain holders of the Company’s then-existing 5.70% Senior Notes due 2039, 3.45% Senior Notes due 2023, 4.875% Senior Notes due 2043 and 7.875% Senior Notes due 2025 (collectively, the Senior Notes) party thereto and certain holders of claims (collectively, the RCF Claims) under the Company’s then-existing $950.0 million syndicated revolving credit facility (or RCF). Concurrently, the Debtors entered into the Backstop Agreement (as defined in the PSA) with certain holders of Senior Notes and entered into the Commitment Letter (as defined in the PSA) with certain holders of RCF Claims to provide exit financing upon emergence from bankruptcy. The Debtors filed a joint Chapter 11 plan of reorganization with the Bankruptcy Court on January 22, 2021, which was subsequently amended on February 24, 2021 and February 26, 2021 (or the Plan). On March 23, 2021, the Debtors filed the plan supplement for the Plan with the Bankruptcy Court, which was subsequently amended on April 6, 2021 and April 22, 2021 (or the Plan Supplement). On April 8, 2021, the Bankruptcy Court entered an order confirming the Plan (or the Confirmation Order). On April 23, 2021 (or the Effective Date), all conditions precedent to the Plan were satisfied, the Plan became effective in accordance with its terms, and the Debtors emerged from Chapter 11 reorganization. Upon emergence from the Chapter 11 Cases, we eliminated a net $2.2 billion of debt. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of this report and Note 2 “Chapter 11 Proceedings – Chapter 11 Cases” and Note 11 "Prepetition Revolving Credit Facility, Senior Notes and Exit Debt" to our Consolidated Financial Statements included in Item 8 of this report. Fresh Start Accounting Upon emergence from bankruptcy, we met the criteria for and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board (or FASB) Accounting Standards Codification (or ASC) Topic 852, Reorganizations (or ASC 852), which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. In addition, as a result of the application of fresh start accounting and the effects of the implementation 3 of the Plan, the financial statements for the period after April 23, 2021 will not be comparable with the financial statements prior to and including April 23, 2021. References to “Successor” refer to the Company and its financial position and results of operations after the Effective Date (or the year ended December 31, 2022 and the period from April 24, 2021 to December 31, 2021). References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Effective Date (or from January 1, 2021 to April 23, 2021) and the year ended December 31, 2020. See Note 3 “Fresh Start Accounting” to our Consolidated Financial Statements included in Item 8 of this report. Our Fleet Our fleet enables us to offer services in the floater market on a worldwide basis. A floater rig is a type of mobile offshore drilling rig that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs are comprised of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom. Semisubmersibles hold position while drilling either by use of a set of small propulsion units or thrusters that provide dynamic positioning (or DP) to keep the rig on location, or with anchors tethered to the seabed to moor the rig. Although DP semisubmersibles are generally self-propelled, such rigs may be moved long distances with the assistance of tug boats. Non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between locations. A drillship is an adaptation of a ship-shaped maritime vessel that is designed and constructed to carry out drilling operations by means of a derrick with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drill site through the use of a DP system. Fleet Status The following table presents additional information regarding our fleet at February 2, 2023: Rig Type and Name DRILLSHIPS (4): Ocean BlackLion Ocean BlackRhino Ocean BlackHornet Ocean BlackHawk SEMISUBMERSIBLES (8): Ocean GreatWhite Ocean Courage Ocean Monarch Ocean Endeavor Ocean Apex Ocean Onyx Ocean Valiant Ocean Patriot MANAGED RIGS (f) West Auriga West Vela Rated Water Depth (in feet)(a) Attributes Year Built/ Redelivered (b) Current Location (c) Customer (d) GOM Senegal GOM Senegal BP Woodside BP Woodside North Sea/U.K. Brazil Malaysia North Sea/Norway/U.K. Australia Malaysia North Sea/U.K. North Sea/U.K. Contract Prep; BP Petrobras Cold Stacked Shipyard/Shell Woodside Cold Stacked Cold Stacked Apache (e) GOM GOM BP Beacon 12,000 DP; MPD; 7R; 15K 12,000 DP; 7R; 15K 12,000 DP; MPD; 7R; 15K 12,000 DP; 7R; 15K 10,000 DP; 6R; 15K 10,000 DP; 6R; 15K 10,000 15K 10,000 15K 6,000 15K 6,000 15K 5,500 15K 3,000 15K 10,000 DP; MPD; 15K 10,000 DP; MPD; 15K 2015 2014 2014 2014 2016 2009 2008 2007 2014 2013 1988 1983 2013 2013 4 DP = Dynamically Positioned/Self-Propelled 7R = 2 Seven ram blow out preventers 6R = Six ram blow out preventer Attributes MPD = Managed Pressure Drilling equipped = 15,000 psi well control system 15K (a) Rated water depth for drillships and semisubmersibles reflects the maximum water depth in which a floating rig has been designed for drilling operations. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on various conditions (including, but not limited to, weather and sea conditions). (b) Represents year rig was built and originally placed in service or year rig was redelivered with significant enhancements that enabled the rig to be classified within a different floater category than originally constructed. (c) GOM means U.S. Gulf of Mexico. (d) For ease of presentation in this table, customer names have been shortened or abbreviated. Warm Stacked is used to describe a rig that is idled (not contracted) and maintained in a “ready” state with a crew sized to enable the rig to be quickly placed into service when contracted. Cold Stacked is used to describe an idled rig for which steps have been taken to preserve the rig and reduce certain costs, such as crew costs and maintenance expenses. Depending on the amount of time that a rig is cold stacked, significant expenditures may be required to return the rig to a “ready” state. Contract Prep is used to describe activities undertaken by a rig that is being made ready for a future contract and may include customer-requested modifications to the rig. Shipyard is used to describe a rig that is contracted but currently in a shipyard for regulatory inspections or repair and maintenance activities. Under Contract is used to indicate that a rig has been contracted; however, the customer has not been named. In February 2023, Apache verbally informed us that it intends to exercise its option to terminate its drilling contract for the Ocean Patriot. In accordance with the terms of the drilling contract, the Ocean Patriot will continue to perform services under the contract until at least July 2023. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” (e) (f) Rigs owned by and managed on behalf of Aquadrill LLC. See “—Rig Management and Marketing Services.” Markets The principal markets for our offshore contract drilling services are: • • • the Gulf of Mexico, including the United States, or U.S., and Mexico; Canada; South America, principally offshore Brazil; • Australia and Southeast Asia; • • • Europe, principally offshore the United Kingdom, or U.K.; East and West Africa; and the Mediterranean. We actively market our rigs worldwide. From time to time, our fleet operates in various other markets throughout the world. See Note 18 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report. Offshore Contract Drilling Services Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through a competitive bid process, although it is not unusual for us to be awarded drilling contracts following direct negotiations. Our drilling contracts generally provide for a basic dayrate regardless of whether or not drilling results in a productive well. Drilling contracts generally also provide for reductions in rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of 5 our revenues. In addition, from time to time, our dayrate contracts may also provide us the ability to earn an incentive bonus from our customer based upon performance. The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, which we refer to as a well-to-well contract, or a fixed period of time, which we refer to as a term contract. Our drilling contracts may be terminated by the customer in the event the drilling unit is destroyed or lost, or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to events beyond the control of either party to the contract. Certain of our contracts also permit the customer to terminate the contract early by giving notice; in most circumstances this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally subject to mutually agreeable terms and rates at the time of the extension. In periods of decreasing demand for offshore rigs, drilling contractors may prefer longer term contracts to preserve dayrates at existing levels and ensure utilization, while customers may prefer shorter contracts that allow them to more quickly obtain the benefit of declining dayrates. Moreover, drilling contractors may accept lower dayrates in a declining market in order to obtain longer-term contracts and add backlog. Conversely, in periods of rising demand for offshore rigs, contractors may prefer shorter contracts that allow them to more quickly profit from increasing dayrates, while customers with reasonably definite drilling programs may prefer longer term contracts to maintain dayrate prices at a consistent level. See “Risk Factors – Risks Related to Our Business and Operations – We may not be able to renew or replace expiring contracts for our rigs” and “Risk Factors — Risks Related to Our Business and Operations — Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us,” in Item 1A of this report. For a discussion of our contract backlog, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contract Drilling Backlog” in Item 7 of this report. Rig Management and Marketing Services In May 2021, we entered into an arrangement with Aquadrill LLC (or Aquadrill), an offshore drilling company, whereby we would provide management and marketing services for three rigs (or the MMSA). Per the MMSA, we earn a fixed daily fee for each rig, based on the status of the rig as either cold stacked, warm stacked, reactivation or operating. In addition, while a rig is under the MMSA, we are entitled to reimbursement of direct costs incurred in accordance with the MMSA. When a rig is operating under contract, the MMSA also provides for the payment of a variable fee based on the gross margin attained by the rig, including a bonus/malice component dependent on the financial performance of the rig, plus a commission as a percentage of revenue related to marketing services. We currently manage two drillships, the West Auriga and the West Vela, both of which were contracted as of December 31, 2022. The MMSA for a third rig, the West Capricorn, was terminated in the third quarter of 2022 due to the sale of the rig by its owner. Additionally, we have entered into and are currently operating under charter hire agreements with Aquadrill (or the Charters) for the West Auriga and West Vela for their contracts in the GOM. While the rigs are chartered, the MMSA is suspended and will resume upon termination of the Charters. The terms of the Charters are consistent with the MMSA, resulting in the same financial impact to us had the rigs remained under the MMSA. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contract Drilling Backlog” in Item 7 of this report and Note 4 “Revenue from Contracts with Customers – Revenues Related to Managed Rigs” to our Consolidated Financial Statements in Item 8 of this report. Customers We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through 6 April 23, 2021, and the year ended December 31, 2020, we performed services for seven, eight, ten and twelve different customers, respectively. Our most significant customers during these periods were as follows: Customer BP Woodside Petróleo Brasileiro S.A. Shell Occidental Hess Corporation Successor Predecessor Year Ended December 31, 2022 (1) Period from April 24, 2021 through December 31, 2021 (1) Period from January 1, 2021 through Year Ended April 23, 2021 December 31, 2020 33.1% 29.7% 9.5% 4.1% 3.9% — 25.4% 22.4% 7.6% 5.1% 11.5% — 39.8% 0.5% 2.0% 9.2% 21.4% — 20.6% 7.0% 21.2% 10.1% 20.1% 10.7% (1) Excludes revenues, primarily reimbursable revenue, attributable to the MMSA with Aquadrill of $58.0 million and $45.3 million earned during 2022 and the period from April 24, 2021 through December 31, 2021, respectively. See “— Rig Management and Marketing Services.” No other customer accounted for 10% or more of our annual total consolidated revenues during the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020. See “Risk Factors — Risks Related to Our Business and Operations – Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition” and “Risk Factors — Risks Related to Our Business and Operations — Our customer base is concentrated” in Item 1A of this report. Backlog As of January 1, 2023, our contract backlog was an aggregate $1.8 billion attributable to ten customers, compared to $1.2 billion as of January 1, 2022 also attributable to ten customers. For the five-year period from 2023 to 2027, $1.4 billion (or 81%) of our contracted backlog as of January 1, 2023 was attributable to future operations with three customers, including one customer contracted for five rigs and another customer contracted for three rigs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contract Drilling Backlog” in Item 7 of this report. See “Risk Factors — Risks Related to Our Business and Operations – We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized” in Item 1A of this report. Competition Based on industry data, as of the date of this report, there are approximately 685 mobile drilling rigs (drillships, semisubmersibles and jack-up rigs) in service worldwide, including approximately 190 floater rigs. Despite consolidation in previous years, the offshore contract drilling industry remains highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. We believe we compete favorably with respect to these factors. We compete in a single, global offshore drilling market, but competition may vary significantly by region at any particular time. See “– Markets.” Competition for offshore rigs generally takes place on a worldwide basis, as these rigs are mobile and may be moved, although at a cost that may be substantial, from one region to another. It is characteristic of the offshore drilling industry to move rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. The current market remains very competitive. See “Risk Factors – Risks Related to Our Business and Operations – Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition” in Item 1A of this report. 7 Governmental Regulation and Environmental Matters Our operations are subject to numerous international, foreign, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use. See “Risk Factors – Regulatory and Legal Risks – We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs,” “Risk Factors – Environmental, Social and Governance Risks – Any future regulations relating to greenhouse gases and climate change could have a material adverse effect on our business” and “Risk Factors – Regulatory and Legal Risks – If we, or our customers, are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations” in Item 1A of this report. Human Capital Employees As of December 31, 2022, we managed a global workforce of approximately 2,100 persons including international crew personnel, a portion of whom are furnished through independent labor contractors. A portion of our workforce outside of the U.S. is represented by collective bargaining agreements. As of December 31, 2022, over 57% of our global workforce had been employed by us for five years or more, with an average tenure of approximately 10 years. Core Values and Culture Our global culture is shaped by our Values & Behaviors: • Take Ownership – Run to the challenge; deliver on what you promise. • Go Beyond – Solve tomorrow’s problems today; make it better than you found it. • Have Courage – Challenge conventional thinking; speak up, even when it’s tough. • Exercise Care – Respect that every action has consequences; never cut corners. • Win Together – Learn from each other; share success; champion a “Culture of We.” These core values establish the foundation for our culture and represent the key expectations we have of our employees. Our commitment to Health, Safety and the Environment (or HSE) applies throughout our business. In addition, we recognize the importance of identifying, assessing and promoting Environmental, Social and Governance (or ESG) issues as a fundamental part of conducting business. Along with our core values, we expect our employees to act in accordance with our Code of Business Conduct and Ethics, which we refer to as our Code of Conduct. Our Code of Conduct covers various topics including legal compliance, conflicts of interest, accuracy of financial reporting and disclosure, confidentiality, discrimination and harassment, anti-corruption, safety and health and reporting ethical violations. The Code of Conduct reflects our commitment to operating in a fair, honest, responsible and ethical manner and also provides direction for reporting complaints in the event of alleged violations of our policies (including through an anonymous hotline). Talent Management and Training We take a systemic approach to hiring, training and developing our employees. This includes creating goals aligned to company priorities and providing employees periodic feedback in order to assess and adjust individual performance. We also employ a succession planning process that identifies suitable candidates, and their development needs, for key positions in our company. We generally review the succession plan annually. We provide a comprehensive training program that endeavors to ensure that employees on our rig crews receive position-specific training as an integral part of their career development. We utilize a competency verification program 8 for establishing and verifying the knowledge, skills and abilities needed by each employee to perform their assigned job function in a safe and environmentally sound manner. Safety The safety of our employees and stakeholders is our highest priority. We pride ourselves on being an innovative leader in the development and implementation of sophisticated and efficient job safety programs. We not only try to work safely; we also strive to achieve zero incident operations, or ZIO, through our comprehensive safety initiatives. Achieving ZIO means operating at peak performance and completing each task without harm to our people, the environment or our equipment. Information About Our Executive Officers We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors (or Board) and serve at the discretion of our Board until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below. Name Bernie Wolford, Jr. David L. Roland Dominic A. Savarino Age as of January 31, 2023 Position 63 President, Chief Executive Officer and Director 61 Senior Vice President, General Counsel and Secretary 52 Senior Vice President and Chief Financial Officer Bernie Wolford, Jr. has served as our President, Chief Executive Officer and a member of the Board since May 2021. Mr. Wolford previously served as the Chief Executive Officer and a director of Pacific Drilling S.A., an offshore drilling contractor, from November 2018 to April 2021. From 2010 to 2018, Mr. Wolford served in senior operational roles at Noble Corporation, another offshore drilling contractor, including five years as the company’s Senior Vice President – Operations. David L. Roland has served as our Senior Vice President, General Counsel and Secretary since September 2014. Dominic A. Savarino has served as our Senior Vice President and Chief Financial Officer since September 2021. Mr. Savarino previously served as our Vice President and Chief Accounting & Tax Officer since May 2020 and as our Vice President and Chief Tax Officer since November 2017. Prior to joining Diamond Offshore, Mr. Savarino served as Vice President, Tax at Baker Hughes, Inc. from 2016 to 2017 and held a variety of positions at McDermott International, Inc., including Vice President, Tax from 2015 to 2016. Available Information We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (or the Exchange Act), and accordingly file annual, quarterly and current reports on Forms 10-K, 10-Q and 8-K, respectively, any amendments to those reports and other information with the United States Securities and Exchange Commission (or SEC). Our SEC filings are available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The preceding Internet addresses and all other Internet addresses referenced in this report are for information purposes only and are not intended to be a hyperlink. Accordingly, no information found or provided at such Internet addresses or at our website in general (or at other websites linked to our website) is intended or deemed to be incorporated by reference into this report and such information should not be considered a part of this report or any other filing that we make with the SEC. 9 Disclosure of Material Non-Public Information We announce material information through our filings with the SEC, press releases and/or public conference calls and webcasts. Based on guidance from the SEC, we may also use our website at www.diamondoffshore.com as a means of disclosing material financial information and other material non-public information and for complying with our disclosure obligations under Regulation FD. Such disclosures will be included on our website in the ‘Investors’ section. Accordingly, we encourage investors, the media and others interested in our company to monitor such portions of our website, in addition to following our SEC filings, press releases and public conference calls and webcasts. Item 1A. Risk Factors. Our business is subject to a variety of risks and uncertainties, including those described below, that could have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects. You should carefully consider these risks when evaluating us and our securities. The following material risks and uncertainties are not the only ones facing our company. We are also subject to other risks and uncertainties not known to us or not described below as well as a variety of risks that affect many other companies generally that may also have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects. Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Risks Related to Our Business and Operations • The worldwide demand for drilling services has historically been dependent on the price of oil. • Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical, is currently emerging from a protracted downturn and is significantly affected by many factors outside of our control. • Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition. • We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized. • We may not be able to renew or replace expiring contracts for our rigs. • Our customer base is concentrated. • Our contract drilling expense includes fixed costs that will not decline in proportion to decreases in rig utilization and dayrates. • We must make substantial capital and operating expenditures to reactivate, build, maintain and upgrade our drilling fleet. • Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. • Any significant cyber-attack or other interruption in network security or the operation of critical information technology systems could materially disrupt our operations and adversely affect our business. • Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on us. • We rely on third parties to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction. 10 • • Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability. The impacts of the COVID-19 pandemic and efforts to mitigate the spread of the virus have adversely impacted, and could continue to adversely impact, our business, operations and financial results. • Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility in how we manage our personnel. • • Inflation may adversely affect our operating results and increase working capital investments required to operate our business, Failure to obtain and retain highly skilled personnel could hurt our operations. • As part of our business strategy, we may pursue business opportunities that include acquisitions of businesses or drilling rigs, mergers or joint ventures or other investments, and such transactions would present various risks and uncertainties. Financial and Tax Risks • Our financial performance after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting. • The debt instruments we entered into on the Effective Date contain various restrictive covenants limiting the discretion of our management in operating certain aspects of our business. • Our variable rate indebtedness subjects us to interest rate risk and the transition away from LIBOR could have an adverse impact on us. • The exercise of all or any number of the outstanding Emergence Warrants or the granting or vesting of stock- based awards will dilute the interests of the holders of our New Diamond Common Shares. • We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs. • Changes in tax laws and policies, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results. • Our consolidated effective income tax rate may vary substantially from one reporting period to another. • Changes in accounting principles and financial reporting requirements could adversely affect us. Environmental, Social and Governance Risks • • • Regulations relating to greenhouse gases and climate change could have a material adverse effect on our business. Consumer preference for alternative fuels and electric-powered vehicles may lead to reduced demand for contract drilling services. Increased focus on climate change, the environmental and social impacts of fossil fuel extraction and use and other ESG matters could result in additional costs or risks and adversely impact our business and reputation and our access to capital and ability to refinance our debt. • Global energy supply may shift from our industry's basis, hydrocarbons, to non-hydrocarbon sources, including wind, solar, nuclear and hydroelectric, which, in turn, may adversely affect demand for our services. Regulatory and Legal Risks 11 • We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs. • • If we, or our customers, are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations. Significant portions of our operations are conducted outside the U.S. and involve additional risks not associated with U.S. domestic operations. • We may be subject to litigation and disputes that could have a material adverse effect on us. For a more complete discussion of the material risks facing our business, see below. Risks Related to Our Business and Operations The worldwide demand for drilling services has historically been dependent on the price of oil. Demand for our drilling services depends in large part upon the oil and natural gas industry’s offshore exploration and production activity and expenditure levels, which are directly affected by oil and gas prices and market expectations of potential changes in oil and gas prices. Beginning in the second half of 2014, oil prices declined significantly, resulting in a sharp decline in the demand for offshore drilling services, including services that we provide, and have had a material adverse effect on our results of operations and cash flows compared to years before the decline. Although oil prices have increased from previous lows, the return of low oil prices could stall the recovery of our industry and would continue to have a material adverse effect on many of our customers and, therefore, demand for our services and our financial condition, results of operations and cash flows, including negative cash flows. Oil prices have been, and are expected to continue to be, volatile and are affected by numerous factors beyond our control, including: • worldwide supply and demand for oil and gas; • • • • • • • • • • the level of economic activity in energy-consuming markets; the worldwide economic environment and economic trends, international trade activity; including recessions and the level of the ability of the Organization of Petroleum Exporting Countries, and 10 other oil producing countries, including Russia and Mexico, or OPEC+, to set and maintain production levels and pricing; the level of production in non-OPEC+ countries, including U.S. domestic onshore oil production; civil unrest and the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities involving the Middle East, Russia, Myanmar, other oil-producing regions or other geographic areas or further acts of terrorism in the U.S. or elsewhere, such as the conflict between Russia and Ukraine; the cost of exploring for, developing, producing and delivering oil and gas, both onshore and offshore; the discovery rate of new oil and gas reserves; the rate of decline of existing and new oil and gas reserves and production; available pipeline and other oil and gas transportation and refining capacity; the ability of oil and gas companies to raise capital; • weather conditions, including hurricanes, which can affect oil and gas operations over a wide area; • • • natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills; the policies of various governments regarding exploration and development of their oil and gas reserves; international sanctions on oil-producing countries, or the lifting of such sanctions; 12 • • • • technological advances affecting energy consumption, including development and exploitation of alternative fuels or energy sources; laws and regulations relating to environmental or energy security matters, including those addressing alternative energy sources, the phase-out of fossil fuel vehicles or the risks of global climate change; domestic and foreign tax policy; and advances in exploration and development technology. Although, historically, higher sustained commodity prices have generally resulted in increases in offshore drilling projects, short-term or temporary increases in the price of oil and gas will not necessarily result in an increase in offshore drilling activity or an increase in the market demand for our rigs. The timing of commitment to offshore activity in a cycle depends on project deployment times, reserve replacement needs, availability of capital and alternative options for resource development, among other things. Timing can also be affected by availability, access to, and cost of equipment to perform work. Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical, is currently emerging from a protracted downturn and is significantly affected by many factors outside of our control. Demand for our drilling services depends upon the level of offshore oil and gas exploration, development and production in markets worldwide, and those activities depend in large part on oil and gas prices, worldwide demand for oil and gas and a variety of political and economic factors. The level of offshore drilling activity is adversely affected when operators reduce or defer new investment in offshore projects, reduce or suspend their drilling budgets or reallocate their drilling budgets away from offshore drilling in favor of other priorities, such as renewable energy or land-based projects, which have reduced, and may in the future further reduce, demand for our rigs. As a result, our business and the oil and gas industry in general are subject to cyclical fluctuations. As a result of the cyclical fluctuations in the market, there have been periods of lower demand, excess rig supply and lower dayrates, followed by periods of higher demand, shorter rig supply and higher dayrates. We cannot predict the timing or duration of such fluctuations. Periods of lower demand or excess rig supply intensify the competition in the industry and often result in periods of lower utilization and lower dayrates. During these periods, our rigs may not be able to obtain contracts for future work and may be idle for long periods of time or may be able to obtain work only under contracts with lower dayrates or less favorable terms. Additionally, prolonged periods of low utilization and dayrates have in the past resulted in, and may in the future result in, the recognition of further impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. See “–We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.” Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition. The offshore contract drilling industry remains highly competitive with numerous industry participants. Some of our competitors are larger companies, have larger or more technologically advanced fleets and have greater financial or other resources than we do. The drilling industry has experienced consolidation and may experience additional consolidation, which could create additional large competitors. Moreover, as a result of the recent reductions in demand for oil and natural gas services, certain of our competitors have engaged in bankruptcy proceedings, debt refinancing transactions, management changes or other strategic initiatives in an attempt to reduce operating costs to maintain a favorable position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment are also considered. As of the date of this report, based on industry data, there are approximately 190 floater rigs currently available to meet customer drilling needs in the offshore contract drilling market, and many of these rigs are not currently contracted and/or are cold stacked. 13 In addition, during industry downturns like the one we are emerging from, rig operators may take lower dayrates and shorter contract durations to keep their rigs operational. We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized. Our customers may terminate our drilling contracts under certain circumstances, such as the destruction or loss of a drilling rig, our suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, excessive downtime for repairs, failure to meet minimum performance criteria (including customer acceptance testing) or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods, often by tendering contractually specified termination amounts, which may not fully compensate us for the loss of the contract. In some cases, our drilling contracts may permit the customer to terminate the contract without cause, upon little or no notice or without making an early termination payment to us. During depressed market conditions, certain customers have utilized, and may in the future utilize, such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts. Additionally, because of depressed commodity prices, restricted credit markets, economic downturns, changes in priorities, strategy or government regulations, customer consolidation or other factors beyond our control, a customer may no longer want or need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. For these reasons, customers have sought and may in the future seek to renegotiate the terms of our existing drilling contracts, terminate our contracts without justification or repudiate or otherwise fail to perform their obligations under our contracts. As a result of such contract renegotiations or terminations, our contract backlog has been and may in the future be adversely impacted. We might not recover any compensation (or any recovery we obtain may not fully compensate us for the loss of the contract) and we may be required to idle one or more rigs for an extended period of time. These results in some cases in the past have had, and may in the future have, a material adverse effect on our financial condition, results of operations and cash flows. See “- Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition”. We may not be able to renew or replace expiring contracts for our rigs. Our ability to renew or replace expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers, at such times. Given the historically cyclical and highly competitive nature of our industry, we may not be able to renew or replace the contracts or we may be required to renew or replace expiring contracts or obtain new contracts at dayrates that are below existing dayrates, or that have terms that are less favorable to us, including shorter durations, than our existing contracts. Moreover, we may be unable to secure contracts for these rigs. Failure to secure contracts for a rig may result in a decision to cold stack the rig, which puts the rig at risk for impairment and may competitively disadvantage the rig as many customers have expressed a preference for ready or warm-stacked rigs over cold-stacked rigs. If a decision is made to cold stack a rig, our operating costs for the rig are typically reduced; however, we will incur additional costs associated with cold stacking the rig (particularly if we cold stack a newer rig, such as a drillship or other DP semisubmersible rig, for which cold-stacking costs are typically substantially higher than for an older non- DP rig). In addition, the costs to reactivate a cold-stacked rig may be substantial. See “– We must make substantial capital and operating expenditures to reactivate, build, maintain and upgrade our drilling fleet.” Our customer base is concentrated. We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During the Successor period for the year 2022, our two customers in the GOM (in the aggregate) and one customer with operations in the GOM, Senegal and Australia accounted for 37% and 30%, respectively, of our total consolidated revenue for the year. In addition, the number of customers we have performed services for has declined from 35 in 2014 to nine in 2022. For the five-year period from 2023 to 2027, $1.4 billion (or 78%) of our current contracted backlog is attributable to future operations with three customers, including one customer contracted for five rigs and another customer contracted for three rigs. The loss of a significant customer, whether due to economic or market reasons, reasons of competition or consolidation or any other reason, could have a material adverse impact on our financial condition, results of operations and cash flows, especially in a 14 declining market where the number of our working drilling rigs is declining along with the number of our active customers. In addition, if a significant customer experiences liquidity constraints or other financial difficulties, or elects to terminate one of our drilling contracts, it could have a material adverse effect on our utilization rates in the affected market and also displace demand for our other drilling rigs as the resulting excess supply enters the market. Our contract drilling expense includes fixed costs that will not decline in proportion to decreases in rig utilization and dayrates. Our contract drilling expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs will not decline and often we may incur additional operating costs, such as fuel and catering costs, for which the customer generally reimburses us when a rig is under contract. During times of reduced dayrates and utilization, reductions in costs may not be immediate as we may incur additional costs associated with cold stacking a rig (particularly if we cold stack a newer rig, such as a drillship or other DP semisubmersible rig, for which cold-stacking costs are typically substantially higher than for an older non- DP rig), or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in contract drilling expense. The impacts of the COVID-19 pandemic and efforts to mitigate the spread of the virus have adversely impacted, and could continue to adversely impact, our business, operations and financial results. Beginning in March 2020, the COVID-19 pandemic and the actions taken by businesses and governments in response to it significantly slowed global economic activity and disrupted financial markets and international trade, resulting in a sharp decline in global oil demand and prices. These events had a material adverse effect on our business. Due to worldwide travel restrictions and mandatory quarantine measures designed to prevent or reduce the spread of COVID-19 in certain regions, we experienced increased difficulties, delays and costs in moving our personnel in and out of, and to work in, the various jurisdictions in which we operate. The difficulties and delays resulted in increased costs and a shortage of available experienced rig personnel or rig personnel working unusually long periods before rotating off the rig. In some cases, we were unable to fully recover those increased costs from our customers. We also experienced permitting and regulatory delays attributable to the COVID-19 pandemic or reduced staffing at various regulatory agencies. We also experienced temporary shutdowns due to COVID-19 outbreaks on some of our drilling rigs, which resulted in a loss of revenue. Additionally, we experienced disruptions to or restrictions on the ability of our suppliers, manufacturers and service providers to supply parts, equipment or services in some of the jurisdictions in which we operate, whether as a result of government actions, labor shortages, the inability to source parts or equipment from affected locations, or other effects related to the COVID-19 outbreak, which could have significant adverse consequences on our ability to meet our commitments to customers, including by increasing our operating costs and increasing the risk of rig downtime and contract delays or terminations. While most of these measures and restrictions initially implemented during 2020 have since been relaxed or lifted, any resurgence in COVID-19 infections or new variants of the virus could result in the imposition of new governmental lockdowns, quarantine requirements or other restrictions in an effort to slow the spread of the virus. The ultimate extent of the impact of the COVID-19 outbreak on our business and financial position will continue to depend significantly on future developments, including the emergence of more contagious or vaccine-resistant strains of COVID-19, the future duration, spread or containment of the outbreak, particularly within the geographic locations where we operate, and the related impact on overall economic activity and demand for oil and gas. Many of the other risks we face will be exacerbated by the COVID-19 pandemic and any worsening of the business and economic environment as a result of it. Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility in how we manage our personnel. Outside of the U.S., it is not unusual for us to be subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel costs 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, work stoppages, or threats thereof, and other labor disruptions in certain countries where we operate. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility. 15 Certain legal obligations in the countries in which we operate 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 in these countries could increase our costs and have a material adverse effect on our business, financial condition, results of operations or cash flows. Inflation may adversely affect our operating results and increase working capital investments required to operate our business. Inflationary factors such as increases in labor costs, material costs and overhead costs have adversely affected, and may continue to adversely affect, our operating results. Inflationary pressures may also increase other costs to operate or reactivate our drilling rigs. Our contracts for our drilling rigs generally provide for the payment of an agreed dayrate per rig operating day. Although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur on the project, we may not be able to fully recover increased costs due to inflation from our customers. If we are unable to recoup such increased costs, our operating margins will decline. Continuing or worsening inflation could significantly increase our operating expenses and capital expenditures, which could in turn have a material adverse effect on our business, financial condition, results of operations or cash flows. We must make substantial capital and operating expenditures to reactivate, build, maintain and upgrade our drilling fleet. Our business is highly capital intensive and dependent on having sufficient cash flow and/or available sources of financing in order to fund our capital expenditure requirements. Our expenditures could increase as a result of changes in offshore drilling technology; the cost of labor and materials; customer requirements; the cost of replacement parts for existing drilling rigs; the geographic location of the rigs; 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, safety or other equipment standards, including those relating to the COVID-19 pandemic, 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. Depending on the length of time that a rig has been cold 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. Market conditions, such as during an industry downturn, 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 our capital and operating expenditures. Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes, and the frequency and severity of such natural disasters could be increased due to climate change. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel and damage to producing or potentially productive oil and gas formations, oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to marine hazards, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of suppliers or subcontractors to perform or supply goods or services or personnel shortages. Any of the foregoing events could result in significant damage or loss to our properties and assets or the properties and assets of others, injury or death to rig personnel or others, significant loss of revenues and significant damage claims against us. Our drilling contracts with our customers provide for varying levels of indemnity and allocation of liabilities between our customers and us with respect to the hazards and risks inherent in, and damages or losses arising out of, our operations, and we may not be fully protected. Our contracts are individually negotiated, and the levels of indemnity and allocation of liabilities in them can vary from contract to contract depending on market conditions, 16 particular customer requirements and other factors existing at the time a contract is negotiated. We may incur liability for significant losses or damages under such provisions. Additionally, the enforceability of indemnification provisions in our contracts may be limited or prohibited by applicable law or such provisions may not be enforced by courts having jurisdiction, and we could be held liable for substantial losses or damages and for fines and penalties imposed by regulatory authorities. The indemnification provisions in our contracts may be subject to differing interpretations, and the laws or courts of certain jurisdictions may enforce such provisions while other laws or courts may find them to be unenforceable. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is unsettled under certain laws that are applicable to our contracts. There can be no assurance that our contracts with our customers, suppliers and subcontractors will fully protect us against all hazards and risks inherent in our operations. There can also be no assurance that those parties with contractual obligations to indemnify us will be financially able to do so or will otherwise honor their contractual obligations. We maintain liability insurance, which generally includes coverage for environmental damage; however, because of contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim costs. In addition, certain risks and contingencies related to pollution, reservoir damage and environmental risks are generally not fully insurable. Although we currently have loss-of-hire insurance on certain rigs to cover lost cash flow when a rig is damaged (other than when caused by named windstorms in the U.S. Gulf of Mexico), we have not purchased loss-of-hire insurance for our entire fleet. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks. In addition, our insurance may not cover losses associated with pandemics such as the COVID-19 pandemic. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of material losses that are not covered by third party insurance contracts. In addition, certain of our shore-based facilities are located in geographic regions that are susceptible to damage or disruption from hurricanes and other weather events. Future hurricanes or similar natural disasters that impact our facilities, our personnel located at those facilities or our ongoing operations may negatively affect our financial position and operating results. If an accident or other event occurs that exceeds our insurance coverage limits or is not an insurable event under our insurance policies, or is not fully covered by contractual indemnity, it could result in a significant loss to us and could have a material adverse effect on our financial condition, results of operations and cash flows. Any significant cyber-attack or other interruption in network security or the operation of critical information technology systems could materially disrupt our operations and adversely affect our business. Our business has become increasingly dependent upon information technologies, computer systems and networks, including those maintained by us and those maintained and provided to us by third parties (for example, “software- as-a-service” and cloud solutions), to conduct day-to-day operations, and we are placing greater reliance on information technology to help support our operations and increase efficiency in our business functions. We are dependent upon our information technology and infrastructure, including operational and financial computer systems, to process the data necessary to conduct almost all aspects of our business. Computer, telecommunications and other business facilities and systems could become unavailable or impaired from a variety of causes including, among others, storms and other natural disasters, terrorist attacks, utility outages, theft, design defects, human error or complications encountered as existing systems are maintained, repaired, replaced or upgraded. It has been reported that known or unknown entities or groups have mounted so-called “cyber-attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. In addition, the U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Cybersecurity risks and threats continue to grow and may be difficult to anticipate, prevent, discover or mitigate. A breach, failure or circumvention of our computer systems or networks, or those of our customers, vendors or others with whom we do business, including by ransomware or other attacks, could materially disrupt our business operations and our customers’ operations and could result in the alteration, loss, theft or corruption of data, and unauthorized release of, unauthorized access to, or our loss of access to confidential, proprietary, sensitive 17 or other critical data or systems concerning our company, business activities, employees, customers or vendors. As of the date of this report, many of our non-operational employees, including employees at our corporate headquarters, have a hybrid work arrangement, working both in the office and remotely, which increases various logistical challenges, inefficiencies and operational risks. Working remotely has significantly increased the use of remote networking and online conferencing services that enable employees to work outside of our corporate infrastructure and, in some cases, use their own personal devices. This “remote work” model has resulted in increased demand for information technology resources and may expose us to risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions as a consequence of more employees accessing sensitive and critical information from remote locations. Any such breach, failure or circumvention could result in loss of customers, financial losses, regulatory fines, substantial damage to property, bodily injury or loss of life, or misuse or corruption of critical data and proprietary information, could subject us to significant liabilities and could have a material adverse effect on our operations, financial condition, business or reputation. Further, as cyber incidents continue to evolve, we may be required to incur additional costs to continue to modify or enhance our protective measures or to investigate or remediate the effects of cyber incidents. Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations. Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could adversely affect the market for offshore drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future. We rely on third-party suppliers, manufacturers and service providers to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction. Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes us to volatility in the quality, price and availability of such items. Certain components, parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well as an increase in operating costs and an increased risk of additional asset impairments. Additionally, some of our suppliers, manufacturers and service providers have been negatively impacted by the industry downturn, global economic conditions (including inflation) and/or COVID-19 pandemic. If certain of our suppliers, manufacturers or service providers were to experience significant cash flow issues, become insolvent or otherwise curtail or discontinue their business as a result of such conditions, it could result in a reduction or interruption in supplies, equipment or services available to us and/or a significant increase in the price of such supplies, equipment and services. Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts. Our contracts for our drilling rigs generally provide for the payment of an agreed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur on the project. Over the term of a drilling contract, our operating costs may fluctuate due to inflation or other events beyond our control. In addition, equipment repair and maintenance expenses vary depending on the type of activity the rig is performing, the age and condition of the equipment and general market factors impacting relevant parts, components and services. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers. 18 Failure to obtain and retain highly skilled personnel could hurt our operations. We require highly skilled personnel to operate and provide technical services and support for our business. A well-trained, motivated and adequately-staffed work force has a positive impact on our ability to attract and retain business. As a result, our future success depends on our continuing ability to identify, hire, develop, motivate and retain skilled personnel for all areas of our organization. To the extent that demand for drilling services and/or the size of the active worldwide industry fleet increases, shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs. Our continued ability to compete effectively depends on our ability to attract new employees and to retain and motivate our existing employees. Heightened competition for skilled personnel could materially and adversely limit our operations and further increase our costs. In addition, the unexpected loss of members of management, qualified personnel or a significant number of employees due to disease, including COVID-19, disability or death, could have a material adverse effect on us. As part of our business strategy, we may pursue business opportunities that include acquisitions of businesses or drilling rigs, mergers or joint ventures or other investments, and such transactions would present various risks and uncertainties. We may pursue transactions that involve the acquisition of businesses or assets, mergers or joint ventures or other investments that we believe will enable us to further expand or enhance our business. Any such transaction would be evaluated on a case-by-case basis, and its consummation would depend upon numerous factors, including identifying suitable targets or assets that align with our business strategy, reaching agreement with the potential counterparties on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions. Any such transactions would involve various risks including, among others, the following: • • • • • difficulties related to integrating or managing applicable parts of an acquired business or joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing; diversion of management’s attention from day-to-day operations; failure to realize anticipated benefits, such as cost savings, revenue enhancements or business synergies; the potential for substantial transaction expenses; and potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time any such transaction is consummated. Financial and Tax Risks Our financial performance after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting. Our capital structure was significantly impacted by the Plan. We emerged from bankruptcy under Chapter 11 of the Bankruptcy Code on April 23, 2021. Upon our emergence from bankruptcy, we adopted fresh start accounting. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. Accordingly, because fresh start accounting rules apply, our financial condition and results of operations following emergence from the Chapter 11 Cases may not be comparable to the financial condition or results of operations reflected in our historical financial statements prior to our emergence from bankruptcy. The debt instruments we entered into on the Effective Date contain various restrictive covenants limiting the discretion of our management in operating certain aspects of our business. Our debt instruments contain various restrictive covenants that may limit our management’s discretion in certain respects and contain negative covenants that limit the borrower's ability and the ability of its restricted subsidiaries to, among other things and subject to a number of important limitations and exceptions: • incur, assume or guarantee additional indebtedness; 19 • create, incur or assume liens; • make investments; • • • • • • enter into sale and leaseback transactions; pay dividends or distributions on capital stock or redeem or repurchase capital stock; enter into transactions with certain affiliates; repay, redeem or amend certain indebtedness; sell stock of its subsidiaries; or enter into certain burdensome agreements. Our failure to comply with these covenants could result in an event of default which, if not cured or waived, could result in all obligations under our debt instruments to be declared due and immediately payable, and all commitments under our revolving credit agreement to be terminated. In addition, our revolving credit agreement obligates the borrower and its restricted subsidiaries to comply with certain financial maintenance covenants and, under certain conditions, to make mandatory prepayments and reduce the amount of credit available under the revolving credit agreement. Such mandatory prepayments and commitment reductions may affect cash available for use in our business. See Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” to our Consolidated Financial Statements included in Item 8 of this report. Our variable rate indebtedness subjects us to interest rate risk and the transition away from LIBOR could have an adverse impact on us. Borrowings under our exit term loan credit agreement and exit revolving credit agreement bear interest at variable rates, based on the applicable margin over market interest rates. If market interest rates increase, our cost to borrow under these credit facilities may also increase even if the amount borrowed remains the same, and our net income and cash flows, including cash available for servicing our indebtedness, will correspondingly decrease. Although we may employ hedging strategies such that a portion of the aggregate principal amount outstanding under these credit facilities would effectively carry a fixed rate of interest, any hedging arrangement put in place may not offer complete protection from this risk. Additionally, financial markets are in the process of transitioning away from the London Interbank Offered Rate (or LIBOR) to alternative benchmark rate(s), which transition is scheduled to be complete by mid-2023. At this time, there can be no assurance as to whether any alternative benchmark or resulting interest rates may be more or less favorable than LIBOR or any other unforeseen impacts of the discontinuation of LIBOR. As a result, the proposals or consequences related to this transition could adversely affect our debt service obligations, financing costs, liquidity, financial condition, results of operations or cash flows and could impair our access to the capital markets. The exercise of all or any number of the outstanding Emergence Warrants or the granting or vesting of stock- based awards will dilute the interests of the holders of our New Diamond Common Shares. On the Effective Date, our new organizational documents became effective authorizing the issuance of shares of common stock representing 100% of the equity interests in the Company as reorganized on the Effective Date in accordance with the Plan (or the New Diamond Common Shares). Also on the Effective Date, and pursuant to the Plan, we entered into a warrant agreement which provides for the issuance of an aggregate of 7.5 million five-year warrants (or the Emergence Warrants). The Emergence Warrants have an exercise period of five years and are exercisable into 7% of the New Diamond Common Shares measured at the time of the exercise. The Emergence Warrants are initially exercisable for one New Diamond Common Share per Emergence Warrant at an exercise price of $29.22 per Emergence Warrant. 20 Additionally, pursuant to the terms of the Plan, the Diamond Offshore Drilling, Inc. 2021 Long-Term Stock Incentive Plan (or the Equity Incentive Plan) was adopted and approved on the Effective Date. The Equity Incentive Plan provides for the grant of stock options, stock appreciation rights (or SARs), restricted stock, restricted stock units (or RSUs), performance awards, and other stock-based awards or any combination thereof to eligible participants. The exercise of the Emergence Warrants or the granting or vesting of equity awards in the future will dilute the interests of the existing holders of our New Diamond Common Shares and could have an adverse effect on the market for the New Diamond Common Shares, including the price that an investor could obtain for such shares. We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs. An oversupply of drilling rigs in the offshore drilling market has resulted in numerous rigs being idled and, in some cases, retired and/or scrapped over the past several years. We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We have incurred impairment charges in the past, and may incur additional impairment charges in the future related to the carrying value of our drilling rigs. Impairment write-offs could result if, for example, any of our rigs become obsolete or commercially less desirable due to changes in technology, market demand or market expectations or their carrying values become excessive due to the condition of the rig, cold stacking the rig, the expectation of cold stacking the rig in the near future, a decision to retire or scrap the rig, or spending in excess of budget on a newbuild, construction project, reactivation or major rig upgrade. We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment, reflecting management’s assumptions and estimates regarding the appropriate risk-adjusted dayrate by rig, future industry conditions and operations and other factors. Asset impairment evaluations are, by their nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets, which could impact the need to record an impairment charge and the amount of any charge taken. From 2012 to the date of this report, we have retired and sold 39 drilling rigs and recorded impairment losses aggregating $2.9 billion. Historically, the longer a drilling rig remains cold stacked, the higher the cost of reactivation and, depending on the age, technological obsolescence and condition of the rig, the lower the likelihood that the rig will be reactivated at a future date. The current oversupply of rigs in our industry heightens the risk of future rig impairments. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Property, Plant and Equipment” in Item 7 of this report and Note 5 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report. We can provide no assurance that our assumptions and estimates used in our asset impairment evaluations will ultimately be realized or that the current carrying value of our property and equipment will ultimately be realized. Changes in tax laws and policies, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results. Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our worldwide operations through various subsidiaries in a number of countries throughout the world. As a result, we are subject to highly complex tax laws, regulations and income tax treaties within and between the countries in which we operate as well as countries in which we may be resident, which may change and are subject to interpretation. In addition, in several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with each other to provide specialized services and equipment in support of our foreign operations. In such cases, we apply an intercompany transfer pricing methodology to determine the arm’s length amount to be charged for providing the services and equipment. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. As a result, we determine our income tax expense based on our interpretation of the applicable tax laws and regulations in effect in each jurisdiction for the period during which we operate and earn income. Our overall effective tax rate could be adversely affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax laws, tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, changes in laws, treaties 21 and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial. Our income tax returns are subject to review and examination. We recognize the benefit of income tax positions we believe are more likely than not to be sustained on their merit should they be challenged by a tax authority. If any tax authority successfully challenges any tax position taken or any of our intercompany transfer pricing policies, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to us or our operations, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially. Our consolidated effective income tax rate may vary substantially from one reporting period to another. Our consolidated effective income tax rate is impacted by the mix between our domestic and international pre- tax earnings or losses, as well as the mix of the international tax jurisdictions in which we operate. We cannot provide any assurance as to what our consolidated effective income tax rate will be in the future due to, among other factors, 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.S. and foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. This variability may cause our consolidated effective income tax rate to vary substantially from one reporting period to another. Changes in accounting principles and financial reporting requirements could adversely affect our results of operations or financial condition. We are required to prepare our financial statements in accordance with accounting principles generally accepted in the U.S. (or GAAP), as promulgated by the FASB. It is possible that future accounting standards that we are required to adopt could change the current accounting treatment that we apply to our consolidated financial statements and that such changes could have a material adverse effect on our results of operations and financial condition. Environmental, Social and Governance Risks Regulations relating to greenhouse gases and climate change could have a material adverse effect on our business. Governments around the world are increasingly considering and adopting laws and regulations to address climate change issues. Lawmakers and regulators in the U.S. and other jurisdictions where we operate have focused increasingly on restricting the emission of carbon dioxide, methane and other “greenhouse” gases and have proposed or enacted regulations requiring reporting of greenhouse gas emissions and restricting such emissions, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy. For example, the SEC has proposed a mandatory climate change reporting framework that, if implemented, is likely to materially increase the amount of time, monitoring and reporting costs related to these matters. These and other new environmental regulations may unfavorably impact us, our suppliers and our customers. In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be materially adversely affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our drilling rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations. Moreover, there is increased focus, including by governmental and non-governmental organizations, investors and other stakeholders on these and other sustainability matters. 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. 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. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have been enacted in some 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, which may reduce demand for oil and natural gas and our drilling services. Such policies or other laws, regulations, treaties and international agreements related to greenhouse 22 gases, climate change, carbon emissions or energy use may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons and thereby reduce demand for our drilling services, limit drilling in the offshore oil and natural gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which could materially adversely affect our business, operations, financial condition, operating results or cash flows. Consumer preference and increasing demand for alternative fuels, energy sources and electric-powered vehicles may lead to reduced demand for contract drilling services. The increasing penetration of renewable energy into the energy supply mix, and consumer preference and increasing demand for alternative fuels, energy sources and electric-powered vehicles may adversely impact the demand for oil and natural gas and, consequently, our contract drilling services. The evolving shift of the global energy system from fossil-based and other non-renewable energy sources to more renewable energy sources, commonly referred to as the energy transition, could have a material adverse impact on our results of operations, financial position and cash flows. As a result of changes in consumer preferences and uncertainty regarding the pace of the energy transition and expected impacts on oil and natural gas demand, some customers are transitioning their businesses to renewable energy projects and away from oil and natural gas exploration and production, which could result in reduced capital spending on oil and natural gas projects and in turn reduced demand for contract drilling services. Increased focus on climate change, the environmental and social impacts of fossil fuel extraction and use, and other ESG matters could result in additional costs or risks and adversely impact our business and reputation and our access to capital and ability to refinance our debt. Stakeholders, such as investors, customers, regulators and the lending community, have increased their focus on environmental, social and governance matters, including practices related to greenhouse gas emissions and climate change. Additionally, an increasing percentage of the investment community considers sustainability factors in making investment decisions, and an increasing number of entities are considering sustainability factors in awarding business. If we are unable to meet our commitments and targets and appropriately address sustainability enhancement, we may lose customers or business partners, and our reputation may be negatively affected. It may be more difficult for us to compete effectively, all of which could have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects. Moreover, in recent years some leading asset managers have expressed a commitment to divest from investments in fossil fuels due to concerns over climate change, and some pension and endowment funds and other investors have begun to divest fossil fuel equities and pressure lenders to limit funding to companies engaged in the extraction of fossil fuels. These efforts intensified during the COVID-19 pandemic, both in the U.S. and throughout the world. In addition, the increased focus by the investment community on ESG-related practices and disclosures, including emission rates and overall impacts to global climate, has created, and will create for the foreseeable future, increased pressure regarding enhancement and modification of the disclosure and governance practices in our industry. The initiatives aimed at limiting climate change and reducing air pollution and the emission of greenhouse gases, including divestment from the oil and gas industry, could significantly interfere with our operations and business activities and restrict our ability to access the capital markets and refinance our debt. 23 Global energy supply may shift from our industry's basis, hydrocarbons, to non-hydrocarbon sources, including wind, solar, nuclear and hydroelectric, which, in turn, may adversely affect demand for our services. Our business involves the extraction of hydrocarbons or fossil fuels from the seabed. The U.S. Energy Information Administration anticipates that oil and natural gas will continue to account for a significant portion of energy fuel mix both in the U.S. and globally through 2040. However, driven by concerns over the risks of climate change, a number of countries have adopted or are considering the adoption of regulatory frameworks to reduce greenhouse gas emissions, including emissions from the production and use of oil and gas and their product, with an ultimate goal of the abolishment of coal and other non-renewable energy sources such as oil and gas. Energy transition, or the shift to sustainable economies by means of renewable energy, has become more prevalent due to the negative effects of climate change. As our customers become more fully committed to energy transition, demand for our services may decrease. A decrease in demand for our services could have a material adverse effect on our financial condition, results of operations and cash flows. Regulatory and Legal Risks We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs. Certain countries are subject to restrictions, sanctions and embargoes imposed by the U.S. government or other governmental or international authorities. These restrictions, sanctions and embargoes may prohibit or limit us from participating in certain business activities in those countries. Our operations are also subject to numerous local, state and federal laws and regulations in the U.S. and in foreign jurisdictions concerning the containment and disposal of hazardous materials, the remediation of contaminated properties and the protection of the environment. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. Failure to comply with such laws and regulations could subject us to civil or criminal enforcement action, for which we may not receive contractual indemnification or have insurance coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected areas. We may be required to make significant expenditures for additional capital equipment or inspection and recertification thereof to comply with existing or new governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or result in a substantial reduction in revenues associated with downtime required to install such equipment or may otherwise significantly limit drilling activity. In addition, these laws and regulations require us to perform certain regulatory inspections, which we refer to as a special survey. For most of our rigs, these special surveys are due every five years, although the inspection interval for our North Sea rigs is two-and-one-half years. Our operating income is negatively impacted during these special surveys. These special surveys are generally performed in a shipyard and require scheduled downtime, which can negatively impact operating revenue. Operating expenses may also increase as a result of these special surveys due to repair and maintenance costs that arise as a result of the inspection process. Repair and maintenance activities may also have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter. Operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between special surveys. Although an intermediate survey normally does not require shipyard time, the survey may require some downtime for the rig. We can provide no assurance as to the exact timing and/or duration of downtime and/or the costs or lost revenues associated with regulatory inspections, planned rig mobilizations and other shipyard projects. In addition, the offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, can be affected by changes in tax and other laws relating to the energy business generally. In addition, the energy sector could be negatively impacted by executive orders and suspensions, as the administration focuses on the impact of climate change, targeting a fully clean energy economy and net-zero emissions by 2050. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could limit drilling opportunities. 24 U.S. federal, state, foreign and international laws and regulations address oil spill prevention and control and impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. Some of these laws and regulations have significantly expanded liability exposure across all segments of the oil and gas industry. For example, the United States Oil Pollution Act of 1990 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages. Failure to comply with such laws and regulations could subject us to civil or criminal enforcement action, for which we may not receive contractual indemnification or have insurance coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected areas. In addition, legislative and regulatory developments may occur that could substantially increase our exposure to liabilities that might arise in connection with our operations. If we, or our customers, are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations. Oil and natural gas exploration and production operations require numerous permits and approvals for us and our customers from governmental agencies in the areas in which we operate or expect to operate. Depending on the area of operation, the burden of obtaining such permits and approvals to commence such operations may reside with us, our customers or both. Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse change in the interpretation of existing permits and approvals. In addition, such regulatory requirements and restrictions could also delay or curtail our operations. Significant portions of our operations are conducted outside the U.S. and involve additional risks not associated with U.S. domestic operations. Our operations outside the U.S. accounted for approximately 53%, 41%, 55% and 54% of our total consolidated revenues for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, respectively, and include, or have included, operations in Senegal, Brazil, Australia, Myanmar and the U.K. Because we operate in various regions throughout the world, we are exposed to a variety of risks inherent in international operations, including risks of war or conflicts; political and economic instability and disruption; civil disturbance; acts of piracy, terrorism or other assaults on property or personnel; corruption; possible economic and legal sanctions (such as possible restrictions against countries that the U.S. government may consider to be state sponsors of terrorism); changes in global monetary and trade policies, laws and regulations; fluctuations in currency exchange rates; restrictions on currency exchange; controls over the repatriation of income or capital; and other risks. We may not have insurance coverage for these risks, or we may not be able to obtain adequate insurance coverage for such events at reasonable rates. Our operations may become restricted, disrupted or prohibited in any country in which any of these risks occur. On January 29, 2020, the European Parliament approved the U.K.’s withdrawal from the European Union, commonly referred to as Brexit. The U.K. officially left the European Union on January 31, 2020. In December 2020, the U.K. and the European Union announced they had entered into a post-Brexit agreement regarding certain aspects of trade and other strategic and political issues, potentially avoiding some of the anticipated disruption of a no-deal Brexit. The impact of Brexit, the December 2020 post-Brexit agreement between the U.K. and the European Union, and the terms of their post-Brexit relationship not addressed in that agreement, as well as the future relationship between the U.K. and the European Union, remain uncertain for companies that do business in the U.K. and the overall global economy. Approximately 9%, 18% and 11% of our total revenues for the Successor period for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively, were generated in the U.K. The effects of Brexit and the December 2020 post-Brexit agreement between the U.K. and the European Union, or similar events in other jurisdictions, could depress economic activity or impact global markets, including foreign exchange and securities markets, which may have an adverse impact on our business and operations as a result of changes in currency exchange rates, tariffs, treaties and other regulatory matters. We are also subject to the following risks in connection with our international operations: 25 • • • • • • • • • • • • • • • kidnapping of personnel; seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of property or equipment; renegotiation or nullification of existing contracts; disputes and legal proceedings in international jurisdictions; changing social, political and economic conditions; imposition of wage and price controls, trade barriers, export controls or import-export quotas; difficulties in collecting accounts receivable and longer collection periods; fluctuations in currency exchange rates and restrictions on currency exchange; regulatory or financial requirements to comply with foreign bureaucratic actions; restriction or disruption of business activities; limitation of our access to markets for periods of time; travel limitations or operational problems caused by public health threats, including the COVID-19 pandemic, or changes in immigration policies; difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations; difficulties in obtaining visas or work permits for our employees on a timely basis; and changing taxation policies and confiscatory or discriminatory taxation. We are also subject to the regulations of the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations in addition to domestic and international anti- bribery laws and sanctions, trade laws and regulations, customs laws and regulations, and other restrictions imposed by other governmental or international authorities. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to us, among other things. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act 2010 or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions. In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling rigs; import-export quotas or other trade barriers; repatriation of foreign earnings or capital; oil and gas exploration and development; local content requirements; taxation of offshore earnings and earnings of expatriate personnel; and use and compensation of local employees and suppliers by foreign contractors. 26 We may be subject to litigation and disputes that could have a material adverse effect on us. We are, from time to time, involved in litigation and disputes. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters, claims of infringement of patent and other intellectual property rights, and other litigation that arises in the ordinary course of our business. We cannot predict with certainty the outcome or effect of any dispute, claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. We may not have insurance for litigation or claims that may arise, or if we do have insurance coverage it may not be sufficient, insurers may not remain solvent, other claims may exhaust some or all of the insurance available to us or insurers may interpret our insurance policies such that they do not cover losses for which we make claims or may otherwise dispute claims made. Litigation may have a material adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other risk factors inherent in litigation or relating to the claims that may arise. Item 1B. Unresolved Staff Comments. Not applicable. Item 2. Properties. We lease office space in Houston, Texas, where our corporate headquarters are located. Additionally, we lease various office, warehouse and storage facilities in Australia, Brazil, Louisiana, Malaysia, Senegal, Singapore and the U.K. to support our offshore drilling operations. We own offices and other facilities in New Iberia, Louisiana; Aberdeen, Scotland; Macae, Brazil; and Ciudad del Carmen, Mexico. Item 3. Legal Proceedings. See information with respect to legal proceedings in Note 12 “Commitments and Contingencies” to our Consolidated Financial Statements in Item 8 of this report. Item 4. Mine Safety Disclosures. Not applicable. 27 PART II Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Market Information and Holders of Record On the Effective Date, pursuant to the Plan, the Successor company issued an aggregate of approximately 100.0 million shares of common stock, par value $0.0001 per share, representing 100% of the equity interests in the reorganized company, and 7.5 million five-year warrants to purchase our common stock. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of this report and Note 2 “Chapter 11 Proceedings – New Diamond Common Shares and New Warrants” to our Consolidated Financial Statements included in Item 8 of this report. We received approval in the first quarter of 2022 to relist our unrestricted common stock on the New York Stock Exchange (or NYSE) under the ticker symbol “DO.” Our common stock commenced trading on the NYSE on March 30, 2022. As of February 24, 2023, there were approximately 146 holders of record of our common stock. This number represents registered stockholders of record and does not include stockholders who hold their shares through an institution. Dividend Policy The Predecessor company had not paid a dividend to stockholders since 2015. For the Successor company, any future dividends will be at the discretion of our Board after taking into account various factors it deems relevant, including our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and contractual obligations. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. Our ability to declare dividends is generally prohibited by our post-emergence debt. See Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” to our Consolidated Financial Statements included in Item 8 of this report. Cumulative Total Stockholder Return The following chart illustrates the cumulative total stockholder return for our New Diamond Common Shares, the Standard & Poor’s SmallCap 600 Index and the Dow Jones U.S. Oil Equipment & Services Index, assuming $100 invested on March 30, 2022 in our common stock and the two published indices and reinvestment of dividends. The chart depicts the past performance for the period from March 30, 2022, the day our common stock commenced trading on the NYSE, through December 31, 2022, and should not be used to predict future share performance. 28 Comparison of Cumulative Total Return(1) $175 $150 $125 $100 $75 $50 Mar. 31, 2022 Jun. 30, 2022 Sep. 30, 2022 Dec. 31, 2022 Diamond Offshore S&P SmallCap 600 Index Dow Jones U.S. Oil Equipment & Services Diamond Offshore S&P SmallCap 600 Index Dow Jones U.S. Oil Equipment & Services Mar. 30, 2022 Jun. 30, 2022 Sep. 30, 2022 Dec. 31, 2022 $ $ $ 100 100 100 83 86 84 93 81 75 146 89 112 Issuer Purchases of Equity Securities During the Fourth Quarter of 2022 During the three months ended December 31, 2022, in connection with the vesting of restricted stock units held by our officers and certain other employees, which were awarded under an equity incentive compensation plan, we acquired shares of our common stock in satisfaction of tax withholding obligations that were incurred on the vesting date. The date of acquisition, number of shares and average effective acquisition price per share were as follows: Period October 1, 2022 through October 31, 2022 November 1, 2022 through November 30, 2022 December 1, 2022 through December 31, 2022 Total Total Number of Shares Acquired Average Price Paid per Share — $ — 99,776 99,776 $ — — 10.40 10.40 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs N/A N/A N/A N/A Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs N/A N/A N/A N/A Item 6. [Reserved]. 29 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion should be read in conjunction with Item 1A, “Risk Factors” and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report. This section of this Form 10-K generally discusses the Successor periods for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021. For a discussion of our financial condition and results of operations for Successor period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on March 7, 2022. We provide contract drilling services to the energy industry around the globe with a fleet of 14 offshore drilling rigs, consisting of four owned drillships, eight owned semisubmersible rigs and two managed rigs as of the date of this report. On February 10, 2023, Apache Beryl I Limited (or Apache) verbally informed us that it intends to exercise its option to terminate its drilling contract for the Ocean Patriot. In accordance with the terms of the drilling contract, the Ocean Patriot will continue to perform services under the contract until at least July 2023. Prior to the verbal termination notice, we had estimated that the drilling contract, which originally commenced in 2017 and was most recently extended in 2021, would conclude in September 2024. Pursuant to the contract, upon cancellation Apache is obligated to pay an early termination fee of $12.5 million. We will market the Ocean Patriot for new projects to commence after the termination of the Apache contract. Bankruptcy Filing As previously disclosed, on the Petition Date, the Debtors voluntarily commenced the Chapter 11 Cases seeking relief under Chapter 11 in the Bankruptcy Court. On January 22, 2021, the Debtors entered into the PSA, among the Debtors, certain holders of the Company’s then-existing Senior Notes and certain holders of the RCF Claims under the Company’s then-existing $950.0 million syndicated revolving credit facility. Concurrently, the Debtors entered into the Backstop Agreement with certain holders of Senior Notes and entered into the Commitment Letter (as defined in the PSA) with certain holders of RCF Claims to provide exit financing upon emergence from bankruptcy. The Debtors filed a joint Chapter 11 plan of reorganization with the Bankruptcy Court on January 22, 2021, which was subsequently amended on February 24, 2021 and February 26, 2021, which we refer to as the Plan. On March 23, 2021, the Debtors filed the plan supplement for the Plan with the Bankruptcy Court, which was subsequently amended on April 6, 2021 and April 22, 2021, which we refer to as the Plan Supplement. On April 8, 2021, the Bankruptcy Court entered the Confirmation Order confirming the Plan. On April 23, 2021, which we refer to as the Effective Date, all conditions precedent to the Plan were satisfied, the Plan became effective in accordance with its terms, and the Debtors emerged from Chapter 11 reorganization. See “Business – Reorganization and Chapter 11 Proceedings” in Item 1 of this report, “– Liquidity and Capital Resources” and Note 2 “Chapter 11 Proceedings” and Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” to our Consolidated Financial Statements included in Item 8 of this report. Fresh Start Accounting Upon emergence from bankruptcy, we met the criteria for and were required to adopt fresh start accounting in accordance with ASC 852, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. The criteria requiring fresh start accounting are: (i) the holders of the then-existing voting shares of the Predecessor (or legacy entity prior to the Effective Date) received less than 50 percent of the new voting shares of the Successor outstanding upon emergence from bankruptcy, and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims. 30 Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. In addition, as a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the period after April 23, 2021 will not be comparable with the financial statements prior to and including April 23, 2021. References to “Successor” refer to the Company and its financial position and results of operations after the Effective Date (or the year ended December 31, 2022 and the period from April 24, 2021 to December 31, 2021). References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Effective Date (or from January 1, 2021 to April 23, 2021). See Note 3 “Fresh Start Accounting” to our Consolidated Financial Statements included in Item 8 of this report. Market Overview The macro-environment for the energy sector continues to be supported by improving market fundamentals. These fundamentals have prompted a structural upcycle in the sector, as demonstrated by increased 2023 capital investment budgets in the upstream energy sector. In 2022, however, despite favorable market trends, continued inflationary pressures, geopolitical unrest, and market volatility led to continued underinvestment by oil and gas companies. When normalizing 2022 upstream spending to 2021 cost levels, certain industry analysts estimate that 2022 investment was 29% below 2019 levels. We anticipate that increased capital investments by oil and gas companies will be required to mitigate the cumulative impact from this prolonged period of underinvestment. According to industry reports, analysts expect 2023 offshore exploration spending to increase by more than 10% over 2022, with most of the spending focused on North America, South America, the Middle East, Asia and Africa, which are many of the areas in which we have a presence. An increase in offshore exploration would present potential upside for future rig demand. According to pricing data published by the U.S. Energy Information Administration, Brent oil prices averaged approximately $101 per barrel in 2022, which is approximately 42% higher than the 2021 average. In the last 3 months of 2022 Brent oil prices averaged approximately $89 per barrel. In addition, the forward curves for 2023 and 2024 Brent oil prices are anticipated to remain strong and average above $80 per barrel according to industry data. The strong commodity price environment has been supported by a tightening commodity supply outlook with 2022 worldwide production recording only marginal gains. Despite indications of a potential future economic slowdown, the International Energy Agency still expects oil and gas demand to grow by 1.9 million barrels per day in 2023 and reach an estimated 102 million barrels per day. Energy security persisted as a theme throughout 2022, keeping capacity expansion and the diversity of supply in focus for our customers. These positive dynamics have further tightened the market for rigs and may continue supporting the positive trajectory in dayrates and demand for offshore drilling services. In early February 2023, outstanding tenders for deepwater rigs reported by S&P Global represented 49 rig years of demand, a 63% increase versus 30 rig years of demand associated with deepwater tenders in early February 2022. Industry reports show utilization for floating offshore drilling rigs increased for the eighth consecutive quarter in the fourth quarter of 2022. This improvement in utilization has led to a significant increase in deepwater dayrates, with recent industry data indicating dayrates have approximately doubled over the past twelve months. Upward trends in our general market have prompted transactions for stranded rigs and the reactivation of some stacked rigs. This may increase the available overall rig supply going forward, however, supply chain constraints and inflationary pressures could limit the pace at which these rigs can return to the market. These inflationary pressures are also expected to create upward pressure on operating expenses for offshore drillers. Customer capital allocation decisions will continue to affect demand for our services. Investment mixes over time, coupled with energy demand and regulatory measures, could adversely impact demand for offshore drilling services in the long term. Notwithstanding this possibility, global energy demand continues to be strong while energy supplies remain constrained, and we expect increased investment in both traditional and renewable sources of energy to be required in the future, much of which we expect to be invested in finding and producing hydrocarbons in the offshore segment. 31 See “– Contract Drilling Backlog” for future commitments of our rigs during 2023 through 2027. Contract Drilling Backlog Contract drilling backlog, as presented below, includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue to be earned and the actual periods during which revenues will be earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including weather conditions and unscheduled downtime for repairs and maintenance, as well as COVID-19 related delays. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog. See “Risk Factors – Risks Related to Our Business and Operations – We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized” in Item 1A of this report. The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 4 “Revenue from Contracts with Customers” to our Consolidated Financial Statements in Item 8 of this report. Contract drilling backlog includes only future dayrate revenue as described above, while the disclosure in Note 4 excludes dayrate revenue and only reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related to non-distinct promises within our signed contracts. The following table reflects our contract drilling backlog attributable to future operations as of January 1, 2023 (based on information available at that time), October 1, 2022 (the date reported in our Quarterly Report on Form 10- Q for the quarter ended September 30, 2022), and January 1, 2022 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2021) (in millions). Contract Drilling Backlog January 1, 2023 (1) (2) October 1, 2022 (1) (2) January 1, 2022 (1) (2) $ 1,788 $ 1,596 $ 1,191 (1) Contract backlog as of January 1, 2023 has been adjusted to reflect termination of the Apache contract for the Ocean Patriot pursuant to verbal notification received on February 10, 2023 and excludes a $12.5 million early termination fee from Apache, payable upon cancellation of the contract. Previously reported contract backlog included $75.5 million and $73.0 million as of October 1, 2022 and January 1, 2022, respectively, attributable to the term of the contract for the Ocean Patriot for which Apache has verbally notified us of its intent to terminate. (2) Includes contract backlog of $307.7 million, $300.8 million and $116.0 million at January 1, 2023, October 1, 2022 and January 1, 2022, respectively, attributable to customer drilling contracts secured for rigs managed under the MMSA. We entered into the drilling contracts directly with the customer and will receive and recognize revenue under the terms of the contracts. However, pursuant to the terms of the MMSA and the Charter with the rig owner, we will only realize a gross margin equivalent to our management and marketing fee. See “Business – Rig Management and Marketing Services” in Item 1 of this report and Note 4 “Revenue from Contracts with Customers” to our Consolidated Financial Statements in Item 8 of this report. The following table reflects the amounts of our contract drilling backlog by year as of January 1, 2023 (in millions). Contract Drilling Backlog (1) (2) $ 1,788 $ 934 $ 506 $ 141 $ 106 $ 101 Total 2023 2024 2025 2026 2027 For the Years Ending December 31, 32 (1) Includes contract backlog of $269.4 million and $38.3 million in 2023 and 2024, respectively, attributable to customer drilling contracts secured for rigs managed under the MMSA. We entered into the drilling contracts directly with the customer and will receive and recognize revenue under the terms of the contracts. However, pursuant to the terms of the MMSA and the Charter with the rig owner, we will only realize a gross margin equivalent to our management and marketing fee. (2) Excludes a $12.5 million early termination fee from Apache payable upon cancellation of the contract for the Ocean Patriot. The following table reflects the percentage of rig days committed by year as of January 1, 2023. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of days in a particular year). Rig Days Committed (1) 2023 71% For the Years Ending December 31, 2026 2025 2024 7% 9% 32% 2027 7% (1) As of January 1, 2023, includes approximately 340 rig days currently known and scheduled for contract preparation, mobilization of rigs, surveys and extended repair and maintenance projects during 2023. Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows Operating Income. Our operating income is primarily a function of contract drilling revenue earned less contract drilling expenses incurred or recognized. The two most significant variables affecting our contract drilling revenue are the dayrates earned and utilization rates achieved by our rigs, each of which is a function of rig supply and demand in the marketplace. These factors are not entirely within our control and are difficult to predict. We generally recognize revenue from dayrate drilling contracts as services are performed. Consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result. Revenue is affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, we may receive fees for the mobilization and demobilization of equipment. In addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which we may or may not be compensated. We recognize these fees ratably as services are performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation fees received (on either a lump-sum or dayrate basis), as well as direct and incremental costs associated with the mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the term of the related drilling contracts. As noted above, demobilization revenue expected to be received upon contract completion is estimated and is also recognized ratably over the initial term of the contract. Operating income also fluctuates due to varying levels of contract drilling expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment, which generally are not affected by changes in dayrates and short-term reductions in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or warm-stacked state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of our customer when a rig is under contract. However, if a rig is expected to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. The cost of cold stacking a rig can vary depending on the type of rig. The cost of cold stacking a drillship, for example, is typically substantially higher than the cost of cold stacking an older floater rig. The principal components of our operating expenses include direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs associated with training employees can be significant. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit 33 is performing, as well as the age and condition of the equipment and the regions in which our rigs are working. See “– Contractual Cash Obligations – Pressure Control by the Hour®.” COVID-19 Pandemic. Beginning in March 2020, as a result of the COVID-19 pandemic, we experienced increased difficulties, delays and costs in moving our personnel in and out of, and to work in, the various jurisdictions in which we operate. The difficulties and delays resulted in increased costs and a shortage of available experienced rig personnel or rig personnel working unusually long periods before rotating off the rig. In some cases, we were unable to fully recover those increased costs from our customers. We also experienced permitting and regulatory delays attributable to the COVID-19 pandemic or reduced staffing at various regulatory agencies. We also experienced temporary shutdowns due to COVID-19 outbreaks on some of our drilling rigs, which resulted in a loss of revenue. Additionally, we experienced disruptions to or restrictions on the ability of our suppliers, manufacturers and service providers to supply parts, equipment or services in some of the jurisdictions in which we operate, whether as a result of government actions, labor shortages, the inability to source parts or equipment from affected locations, or other effects related to the COVID-19 outbreak, which had and could continue to have significant adverse consequences on our ability to meet our commitments to customers, including by increasing our operating costs and increasing the risk of rig downtime and contract delays or terminations. Most of these measures and restrictions initially implemented during 2020 have since been relaxed or lifted; however, any resurgence in COVID-19 infections or new variants of the virus could result in the imposition of new governmental lockdowns, quarantine requirements or other restrictions in an effort to slow the spread of the virus. We incurred incremental costs of approximately $4.6 million, $8.9 million and $3.9 million related to the COVID- 19 pandemic during the Successor periods for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively. We expect to incur similar types of costs during 2023 but cannot predict the future financial impact of our response to the COVID-19 pandemic. Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Often other vessel maintenance and improvement activities are also performed concurrently with the survey. Survey costs, which generally include mobilization of the vessel into the shipyard, drydocking, support services while in shipyard and the associated survey or inspection costs necessary to maintain class certifications, are deferred and amortized over the survey interval on a straight-line basis. Other costs incurred at the time of the recertification drydocking, which are not related to the recertification of the vessel, are expensed as incurred. Costs for vessel improvements which either extend the vessel’s useful life or increase the vessel's functionality are capitalized and depreciated. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter. During 2023, we expect to spend approximately 340 days of planned downtime, including approximately (i) 110 days for a maintenance project to meet regulatory requirements for the Ocean Apex; (ii) 45 days for the Ocean GreatWhite reactivation and contract preparation activities; (iii) 50 days for the completion of the Ocean Endeavor shipyard work that commenced in 2022; (iv) 100 days for contract preparation and acceptance testing for the Ocean Courage in advance of its new contract expected to commence in the fourth quarter; and (v) 35 days for mobilization and other planned activities. We can provide no assurance as to the exact timing and/or duration of downtime associated with these or other projects. See “ – Contract Drilling Backlog.” Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $10.0 million per occurrence. In addition, we currently carry loss-of-hire insurance on certain rigs to cover lost cash flow when a rig is damaged (other than when caused by named windstorms in the U.S. Gulf of Mexico) but have not purchased loss-of-hire insurance for our entire fleet. 34 In addition, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, collisions, and wreck removals, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Under these marine liability policies, we self-insure $1.0 million to $5.0 million per occurrence, depending on jurisdiction, but up to $25.0 million for liabilities arising out of named windstorms in the U.S. Gulf of Mexico. Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceeds certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence. Impact of Changes in Tax Laws or Their Interpretation. We operate through our various subsidiaries in a number of jurisdictions throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. On August 16, 2022, the Inflation Reduction Act (or the IRA) was enacted by the United States. Among other provisions, the IRA includes a 15% corporate minimum tax rate applied to certain large corporations and a 1% excise tax on corporate stock repurchases made after December 31, 2022. We do not expect these provisions of the IRA to have a material impact on our operating results, financial condition or cash flows. We currently rely on certain benefits of the tax treaty between the United States and Hungary. On July 8, 2022, the U.S. Treasury Department notified Hungary that the United States would terminate the tax treaty with Hungary. In accordance with the treaty’s provisions on termination, termination will be effective on January 8, 2023. However, with respect to taxes withheld at source, the treaty will cease to have effect on January 1, 2024. In respect of other taxes, the treaty ceases to have effect with respect to taxable periods beginning on or after January 1, 2024. We cannot reliably quantify the effect of the treaty’s termination on future periods’ results of operations and cash flows. In October 2021, almost 140 countries in the OECD/G20 Inclusive Framework on Base Erosion and Profit Shifting (BEPS) reached an agreement on international tax reform, including rules to ensure that multinational groups of companies pay a minimum rate corporate income tax. In December 2022, the European Council adopted a Directive requiring European Union member states to implement the minimum taxation component (Pillar 2) of the reforms. Each member state must enact implementing legislation. We are currently assessing how such a minimum tax when enacted will impact our business. Critical Accounting Estimates Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows: Fresh Start Accounting. Upon emergence from bankruptcy, we met the criteria for and were required to adopt fresh start accounting in accordance with ASC 852, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Company's reorganization value approximates the fair value of the Successor’s total assets and the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values (except for deferred income taxes) in conformity with FASB ASC Topic 805, Business Combinations, and FASB ASC Topic 820, Fair Value Measurement. The amount of deferred taxes was determined in accordance with FASB ASC Topic 740, Income Taxes (or ASC 740). Under the application of fresh start accounting and with the assistance of valuation experts, we conducted an analysis of the Consolidated Balance Sheet to determine if any of the Company’s net assets would require a fair value adjustment as of the Effective Date. The results of our analysis indicated that our principal assets, which include drilling and other property and equipment; warehouse stock and fuel inventory; leases; long-term debt and warrants 35 would require a fair value adjustment on the Effective Date. The rest of the Company’s net assets were determined to have carrying values that approximated fair value on the Effective Date with the exception of certain contract assets and liabilities which were written off. Deferred tax assets and uncertain tax positions were determined in accordance with ASC 740 after considering the tax effects of the reorganization and the newly established fair values of the Successor. See Note 3 “Fresh Start Accounting” to our Consolidated Financial Statements included in Item 8 of this report. Property, Plant and Equipment. We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. During the Successor periods for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, we capitalized $69.1 million, $22.0 million and $59.9 million, respectively, in replacements and betterments of our drilling fleet. We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, a change in the economic useful life of a rig, cold stacking a rig, the expectation of cold stacking a rig in the near future, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project, reactivation or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following: • • • • • • • • dayrate by rig; utilization rate by rig if active, warm-stacked or cold-stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates); the per day operating cost for each rig if active, warm-stacked or cold-stacked; the estimated annual cost for rig replacements and/or enhancement programs; the estimated maintenance, inspection or other reactivation costs associated with a rig returning to work; the remaining economic useful life of a rig; salvage value for each rig; and estimated proceeds that may be received on disposition of each rig. Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we assign a probability of occurrence. We arrive at a projected probability-weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability. The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment. Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about 36 future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a sustained decline in oil and gas prices, cancellations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, capital expenditures required due to advances in offshore drilling technology, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. When an impairment is indicated, we have historically estimated the fair value of the impaired rig using an income approach, whereby the fair value of the rig is estimated based on a calculation of the rig’s future net cash flow (on a probability-weighted basis) over its remaining estimated economic useful life, using similar inputs and assumptions as described above, and discounted based on our weighted average cost of capital. These cash flow projections utilized significant unobservable inputs, including management’s assumptions related to estimated dayrate revenue, rig utilization and estimated capital expenditures, repair and regulatory survey costs, as well as estimated proceeds that may be received on ultimate disposition of the rig. We did not incur an impairment loss in 2022. During the Successor period from April 24, 2021 through December 31, 2021, we reviewed the marketability, age and physical condition of certain of our rigs in conjunction with other factors specific to the geographic markets in which these rigs are capable of operating and determined, based on circumstances that arose in the fourth quarter of 2021, which we believed to be other than temporary, that the economic useful lives of certain of the rigs were materially different than that determined at the Effective Date. Based on the revised useful lives, we determined that the carrying values of two semisubmersible rigs were impaired. We recognized an aggregate impairment loss of $132.4 million to write down these rigs to their estimated fair value. During the Predecessor period from January 1, 2021 through April 23 2021, we recognized an impairment loss of $197.0 million for one rig for which we had concerns regarding future opportunities. See “– Results of Operations – Impairment of Assets” and Note 5 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report. Income Taxes. We account for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as net operating loss carryforwards, utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit. In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the arm’s length amount to be charged for providing the services and equipment and utilize outside consultants to assist us in the development of such transfer pricing methodologies. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. 37 Results of Operations Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning, or R-E, days, rig utilization and average daily revenue. The following table presents these three key performance indicators and other comparative data relating to our revenues and operating expenses (in thousands, except days, daily amounts and percentages). REVENUE-EARNING DAYS (1) UTILIZATION (2) AVERAGE DAILY REVENUE (3) CONTRACT DRILLING REVENUE REVENUE RELATED TO REIMBURSABLE EXPENSES TOTAL REVENUES CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION REIMBURSABLE EXPENSES OPERATING INCOME (LOSS) Contract drilling services, net Reimbursable expenses, net Depreciation General and administrative expense Impairment of assets Restructuring and separation costs Gain on disposition of assets Total Operating Loss Other income (expense): Interest income Interest expense Foreign currency transaction loss Reorganization items, net Other, net Loss before income tax benefit (expense) Income tax benefit (expense) NET LOSS $ $ $ $ $ $ $ $ Successor Year Ended December 31, Period from April 24, 2021 through December 31, 2021 2,250 74% 206,800 465,328 90,738 556,066 364,539 89,284 $ $ $ $ $ 2022 3,089 65% 234,600 724,744 116,534 841,278 620,982 114,962 $ 103,762 1,572 (103,478) (70,196) — — 4,895 (63,445) $ 18 (40,423) (3,023) — 1,267 (105,606) 2,395 (103,211) $ 100,789 1,454 (68,504) (53,494) (132,449) — 1,024 (151,180) 3 (26,180) (997) (8,088) 10,752 (175,690) (1,654) (177,344) Predecessor Period from January 1, 2021 through April 23, 2021 724 53% $ $ $ $ $ $ $ 211,800 153,364 16,015 169,379 181,626 15,477 (28,262) 538 (92,758) (15,036) (197,027) — 5,486 (327,059) 30 (34,827) (172) (1,639,763) 398 (2,001,393) 39,404 $ (1,961,989) (1) An R-E day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days. (2) Utilization is calculated as the ratio of total R-E days divided by the total calendar days in the period for all specified rigs in our fleet (including cold-stacked rigs). (3) Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per R- E day. Contract Drilling Revenue. We earned contract drilling revenue of $724.7 million for the Successor year ended December 31, 2022, attributable to 3,089 R-E days and average daily revenue of $234,600. Total utilization for the period was 65%, primarily due to downtime for the Ocean BlackHawk and Ocean Apex for contract preparation activities, including mobilization to location (184 days) and downtime for the Ocean Endeavor (143 days) and the Ocean Patriot (114 days) for structural and other projects, including a special survey for the Ocean Patriot. Additionally, we cold stacked the Ocean Monarch and Ocean Onyx after completion of their respective contracts in 38 the first and third quarters of 2022, respectively. We also commenced reactivation of the Ocean GreatWhite in the second half of 2022 for its contract in the U.K., which is expected to start in early 2023. The increase in average daily revenue, compared to the Successor period from April 24, 2021 through December 31, 2021, reflected higher dayrates earned under new contracts that commenced in 2022 compared to dayrates earned under the rigs’ previous contracts. The managed rigs West Auriga and West Vela commenced operations in the GOM in the first and fourth quarters of 2022, respectively, and earned revenue aggregating $101.1 million. Revenue Related to Reimbursable Expenses. During the Successor year ended December 31, 2022, we recognized gross reimbursable revenue and expenses of $116.5 million, which included $61.3 million earned under the MMSA. Gross reimbursable revenue and expenses for the Successor period from April 24, 2021 through December 31, 2021 were $90.7 million and included $43.9 million earned under the MMSA commencing in June 2021. During the Successor period from April 24, 2021 through December 31, 2021, we earned contract drilling revenue of $465.3 million, attributable to 2,250 R-E days and average daily revenue of $206,800. Total utilization for the period was 74% and reflected planned downtime for the Ocean Courage and Ocean BlackRhino for contract preparation work (132 days), downtime for the Ocean Endeavor and Ocean Patriot for inspections and repairs (85 days) and downtime attributable to stacked rigs (504 days). During the period from April 24, 2021 through December 31, 2021, we recognized $1.5 million of contract drilling revenue pursuant to the MMSA that commenced in May 2021, for which we also recognized gross reimbursable revenue and expenses of $43.8 million. During the Predecessor period from January 1, 2021 through April 23, 2021, we earned contract drilling revenue of $153.4 million attributable to 724 R-E days and average daily revenue of $211,800. Total utilization for the period was 53%, primarily due to planned downtime for contract preparation work for three rigs and the stacking of other rigs between contracts. The Ocean Onyx commenced a new contract in February 2021 after its reactivation, contributing 61 R-E days to the period. Contract Drilling Expense, Excluding Depreciation. During the Successor year ended December 31, 2022, contract drilling expense, excluding depreciation, was $621.0 million, comprised primarily of expenses associated with payroll and benefits ($264.2 million), rig repairs and maintenance ($175.4 million), shorebase costs, overhead and insurance ($79.3 million), equipment rentals ($58.7 million), catering ($21.0 million), mobilization ($19.2 million) and other operating expenses ($3.2 million). Two of the managed rigs commenced drilling operations during the first quarter and fourth quarter of 2022. As a result, the MMSA was suspended and replaced by a charter agreement. We recognized equipment rental expense in the aggregate amount of $11.7 million related to charter rental of the managed rigs. During the Successor period from April 24, 2021 through December 31, 2021, contract drilling expense, excluding depreciation, was $364.5 million, comprised primarily of payroll and benefits costs ($164.5 million), rig repairs, maintenance and inspections ($105.6 million), shorebase costs, overhead and insurance ($47.2 million), equipment rentals ($33.2 million), catering ($12.0 million), and other operating costs in the aggregate ($2.0 million). Contract drilling expense, excluding depreciation, was $181.6 million for the Predecessor period from January 1, 2021 through April 23, 2021, comprised primarily of payroll and benefits costs ($68.4 million), rig repairs and maintenance ($32.8 million), equipment rentals ($24.4 million), shorebase costs and overhead ($15.9 million), amortization of deferred contract preparation and mobilization costs ($9.9 million), catering ($5.1 million), inspections ($3.9 million), freight and transportation ($3.4 million), insurance ($3.1 million) and other operating costs in the aggregate ($14.7 million). Depreciation Expense. Depreciation expense for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 was $103.5 million, $68.5 million and $92.8 million, respectively. The decline in depreciation was primarily due to the fair value remeasurement of our rigs and equipment from the application of fresh start accounting on the Effective Date. 39 General and Administrative Expense. During the Successor year ended December 31, 2022 we incurred general and administrative costs of $70.2 million, which consisted of payroll and benefits-related costs ($39.3 million), professional and legal expenses ($21.4 million) and other administrative costs ($9.5 million). Compensation expense for the period included $5.4 million related to the vesting of certain performance-based restricted stock awards granted in 2021. During the Successor period from April 24, 2021 through December 31, 2021, we incurred general and administrative costs of $53.5 million, which consisted of payroll and benefits-related costs ($29.9 million), professional and legal expenses ($17.6 million) and other administrative costs ($6.0 million). Compensation expense for the period included $8.0 million of severance benefits for certain executives who left our company on or after the Effective Date. Professional and legal costs for the period included costs associated with a stockholder complaint that arose after the Effective Date and legal advisors engaged to assist an independent committee appointed by our Board to explore strategic alternatives to maximize shareholder value. During the Predecessor period from January 1, 2021 through April 23, 2021, we recognized general and administrative expense of $15.0 million comprised of costs related to payroll and benefits ($10.5 million), professional and legal services ($3.0 million) and other administrative costs ($1.5 million). Impairment of Assets. After evaluating circumstances that arose in the fourth quarter of 2021, which we believed to be other than temporary, we reviewed the marketability, age and physical condition of certain of our rigs in conjunction with other factors specific to the geographic markets in which these rigs are capable of operating and determined that the economic useful lives of certain of the rigs in our fleet were materially different than that determined at the Effective Date. Based on the revised useful lives, we determined that the carrying values of two semisubmersible rigs were impaired. We recognized an aggregate impairment loss of $132.4 million to write down these rigs to their estimated fair value in the Successor period from April 24, 2021 through December 31, 2021. During the Predecessor period from January 1, 2021 through April 23 2021, we recognized an impairment loss of $197.0 million for one rig for which we had concerns regarding future opportunities. Gain on Disposition of Assets. During 2022, we sold the Ocean Valor for aggregate proceeds of approximately $6.6 million and recognized a net gain on the transaction of $4.0 million. During the Predecessor period from January 1, 2021 through April 23, 2021, we sold two previously impaired semisubmersible rigs, the Ocean America and Ocean Rover, for an aggregate net pre-tax gain of $4.4 million. Interest Expense. During the Successor year ended December 31, 2022, we incurred interest expense of $40.4 million, comprised of interest related to our exit debt ($29.8 million), our Well Control Equipment (as defined below) finance leases ($10.4 million) and other expense ($0.2 million). During the Successor period from April 24, 2021 through December 31, 2021, we recognized interest expense related to new debt incurred on or after the Effective Date ($18.4 million) and incremental interest expense related to our Well Control Equipment finance leases ($7.8 million). Upon commencement of the Chapter 11 Cases on April 26, 2020, we ceased accruing interest expense on the Senior Notes and borrowings under the RCF. However, due to provisions in the PSA signed in January 2021, we resumed the recognition of interest on our outstanding borrowings under the RCF and accrued interest expense of $34.8 million for the Predecessor period from January 1, 2021 through April 23, 2021, inclusive of a $23.4 million catch-up adjustment for the period from April 26, 2020 to December 31, 2020. Reorganization Items, net. During the Successor period from April 24, 2021 through December 31, 2021, we recognized $8.1 million of professional fees directly related to the Chapter 11 Cases. During the Predecessor period from January 1, 2021 through April 23, 2021, we recognized $1.6 billion in expenses and other net losses directly related to the Chapter 11 Cases, consisting of fresh start valuation adjustments ($2.7 billion), professional fees ($51.1 million), the accrual of a backstop commitment premium related to our First Lien Notes (as defined below) ($10.4 million) and the write-off of a predecessor directors and officers tail insurance 40 policy ($6.9 million). These expenses were partially offset by a net gain on settlement of liabilities subject to compromise ($1.1 billion). Other, Net. During the Successor period from April 24, 2021 through December 31, 2021, we recognized a $10.8 million settlement related to a patent infringement indemnity claim against the supplier of our four drillships. Income Tax (Expense) Benefit. We recorded an income tax benefit of $2.4 million (effective tax rate of 2.27%) for the Successor year ended December 31, 2022, income tax expense of $1.7 million (negative 0.9% effective tax rate) for the Successor period from April 24, 2021 through December 31, 2021, and an income tax benefit of $39.4 million (1.97% effective tax rate) for the Predecessor period from January 1, 2021 through April 23, 2021. The effective tax rate of 2.27% for the Successor year ended December 31, 2022 reflected changes in the domestic and international jurisdictional mix of our pre-tax income and loss and the release of previously recognized valuation allowances. During the Successor period from April 24, 2021 through December 31, 2021, the negative effective tax rate reflected changes in the domestic and international jurisdictional mix of our pre-tax income and loss, which were consequences of realigning substantially all of our assets and operations under a foreign subsidiary. During the Predecessor period from January 1, 2021 through April 23, 2021, our tax benefit was primarily attributable to the adoption of fresh start accounting. Liquidity and Capital Resources New Debt at Emergence On the Effective Date, pursuant to the terms of the Plan, the Company and its subsidiary Diamond Foreign Asset Company entered into the following debt instruments: • • • • a senior secured revolving credit agreement (or the Exit Revolving Credit Agreement), which provides for a $400.0 million senior secured revolving credit facility (or the Exit RCF), maturing on April 22, 2026, and which as of the date of this report has a $75.0 million commitment for the issuance of letters of credit thereunder (see Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” to our Consolidated Financial Statements included in Item 8 of this report); a senior secured term loan credit agreement, which provides for a $100.0 million senior secured term loan credit facility, which is scheduled to mature on April 22, 2027 under which $100.0 million was drawn on the Effective Date (or the Exit Term Loan); an indenture, pursuant to which approximately $85.3 million in aggregate principal amount of 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (or First Lien Notes) maturing on April 22, 2027 were issued on the Effective Date; and approximately $39.7 million in the form of delayed draw note commitments that may be issued as additional First Lien Notes after the Effective Date, none of which had been issued as of December 31, 2022. Our emergence from the Chapter 11 Cases allowed us to significantly reduce our level of indebtedness. The availability of borrowings under the Exit RCF is subject to the satisfaction of certain conditions, including restrictions on borrowings if certain conditions are met. See Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt — Exit Revolving Credit Agreement” to our Consolidated Financial Statements included in Item 8 of this report. See also “– Contractual Cash Obligations” for our short-term and long-term cash requirements related to post- emergence debt. At February 24, 2023, we had borrowings of $162.5 million outstanding under the Exit RCF, including $3.5 million deemed incurred in satisfaction of certain upfront fees payable to the lenders under the prepetition RCF (or 41 PIK Loans). We also had utilized $19.4 million of the Exit RCF for the issuance of a letter of credit. The PIK Loans do not reduce the amount of available commitments under the Exit RCF, and if repaid or prepaid may not be reborrowed. As of February 24, 2023, approximately $221.6 million was available for borrowings or the issuance of letters of credit under the Exit RCF, subject to its terms and conditions. Sources and Uses of Cash Cash Flows and Capital Expenditures For the Successor year ended December 31, 2022, our operating activities provided cash flow of $8.9 million compared to cash flow of $18.9 million and cash usage of $100.1 million during the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively. During the Successor year ended December 31, 2022, cash receipts for contract drilling services ($781.0 million) and funds received from the return of certain collateral deposits ($17.5 million) were partially offset by cash expenditures for contract drilling, shorebase support and general and administrative expenses ($789.6 million). In addition, we made cash capital expenditures of $60.0 million and received $7.6 million from the sale of assets during the period, including a deposit received for the sale of surplus equipment expected be completed in the first quarter of 2023. Principal payments on our Well Control Equipment finance leases were $15.9 million. During the Successor year ended December 31, 2022, we borrowed $94.0 million under the RCF. For the Successor period from April 24, 2021 through December 31, 2021, cash receipts for contract drilling services ($586.0 million) for the period and funds from the return of certain collateral deposits ($6.0 million) offset cash expenditures for contract drilling, shorebase support, general and administrative costs and cash income taxes paid ($537.7 million) and payments to professionals in connection with the Chapter 11 Cases ($35.4 million). Cash outlays for capital expenditures and our Well Control Equipment finance lease obligations during the period aggregated $42.8 million and $9.8 million, respectively. During this Successor period, we reduced outstanding borrowings under the Exit RCF by a net $20.0 million. For the Predecessor period from January 1, 2021 through April 23, 2021, we used $100.1 million for our operating activities. Cash expenditures for contract drilling, shorebase support and general and administrative costs ($240.5 million), payments to professionals in connection with the Chapter 11 Cases ($37.6 million), and net cash income taxes paid ($3.4 million) offset cash receipts for contract drilling services ($181.4 million) for the period. Cash outlays for capital expenditures aggregated $49.1 million for the Predecessor period. As set forth in the Plan, on the Effective Date, we net settled $242.0 million outstanding under the RCF in cash and issued $75.0 million of First Lien Notes. See Note 2 “Chapter 11 Proceedings” and Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” to our Consolidated Financial Statements included in Item 8 of this report. Upgrades and Other Capital Expenditures We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet and our ongoing rig equipment replacement and capital maintenance programs. The amount of cash required to meet our capital commitments is determined by evaluating the need to upgrade our rigs to meet specific customer requirements and our rig equipment enhancement, maintenance and replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and our cash flow forecast. As of the date of this report, we expect cash capital expenditures for 2023 to be approximately $95.0 million to $110.0 million. 42 Contractual Cash Obligations The following table sets forth our contractual cash obligations at December 31, 2022 (in thousands). Contractual Obligations (1) Exit Term Loan (principal and interest) (2) First Lien Notes (principal and interest) (3) Exit RCF borrowings (4) Well Control Equipment services agreement (5) Finance leases (6) Operating leases (6) Total obligations Payments Due By Period Total 2023 2024-2025 2026-2027 $ 147,376 $ 10,528 $ 21,056 $ 115,792 $ 123,409 231,834 112,536 175,342 34,687 9,302 16,606 24,579 26,280 14,937 17,344 32,729 45,501 52,632 8,531 96,763 182,499 42,456 96,430 6,961 $ 825,184 $ 102,232 $ 177,793 $ 540,901 $ Thereafter — — — — — 4,258 4,258 (1) The above table excludes $36.0 million of total net unrecognized tax benefits related to uncertain tax positions that could result in a future cash payment as of December 31, 2022. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. (2) Contractual obligations related to our Exit Term Loan are presented in the table above assuming an interest rate consistent with the rate applied to the principal as of December 31, 2022. (3) Contractual obligations related to our First Lien Notes are presented in the table above assuming a cash interest payment option and include the commitment premium for the undrawn First Lien Notes based on the December 31, 2022 balance. (4) Contractual obligations under our Exit RCF are presented in the table above assuming that the outstanding amount at December 31, 2022 remains drawn until the maturity of the Exit Revolving Credit Agreement and that interest accrues at the same rate applied to such borrowings as of December 31, 2022. (5) Contractual obligations related to our Well Control Equipment services agreement include a commitment to purchase consumable and capital spare parts owned and controlled by the vendor at the end of the service arrangement for a purchase price based on current list prices not to exceed $37.0 million. The table above assumes that such items are purchased at the ceiling price at the end of the agreement in 2026, however, the actual amount may vary as the volume and prices of spares to be purchased are not yet known. See “– Pressure Control by the Hour®.” (6) These contractual obligations are related to finance leases for our Well Control Equipment and include payments related to the exercise of a purchase option for the Well Control Equipment at the end of the original lease term. We have also entered into various operating leases for corporate and shorebase offices, office and information technology equipment, employee housing, vehicles, onshore storage yards and certain rig equipment and tools. See Note 13 “Leases and Lease Commitments” to our Consolidated Financial Statements in Item 8 of this report. Pressure Control by the Hour®. In 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly known as Baker Hughes, a GE company) (or Baker Hughes) to provide services with respect to certain blowout preventer and related well control equipment (or Well Control Equipment) on our four drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the contractual services agreement, we sold the Well Control Equipment on our drillships to a Baker Hughes subsidiary and are leasing it back over separate finance leases. Collectively, we refer to the contractual services agreement and corresponding finance lease agreements with the Baker Hughes affiliate as the PCbtH program. See Note 12 “Commitments and Contingencies” and Note 13 “Leases and Lease Commitments” to our Consolidated Financial Statements in Item 8 of this report. Except for our contractual requirements under the PCbtH program discussed above, we had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2022, except for those related to our direct rig operations, which arise during the normal course of business. 43 Other Commercial Commitments - Letters of Credit We were contingently liable as of December 31, 2022 in the amount of $18.6 million under certain tax, supersedeas and customs bonds that have been issued on our behalf. The letters of credit that collateralize these bonds, aggregating $19.4 million, were issued under the Exit RCF and cannot require collateral except in events of default. The table below provides a list of these obligations in U.S. dollar equivalents by year of expiration (in thousands). Other Commercial Commitments Total For the Years Ending December 31, 2024 2023 2025 Tax bonds Supersedeas bonds Customs bonds Total obligations Other $ $ 15,812 $ 2,600 160 18,572 $ 2,764 $ 2,600 160 5,524 $ — $ — — — $ 13,048 — — 13,048 Operations Outside the U.S. Our operations outside the U.S. accounted for approximately 53%, 41% and 55% of our total consolidated revenues for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively. See “Risk Factors – Regulatory and Legal Risks – Significant portions of our operations are conducted outside the U.S. and involve additional risks not associated with U.S. domestic operations” in Item 1A of this report. Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations, resulting in foreign currency exposure. Currency environments in which we currently have or previously had significant business operations include Australia, Brazil, Egypt, Malaysia, Mexico, Trinidad and Tobago and the U.K., creating exposure to certain monetary assets and liabilities denominated in currencies other than the U.S. dollar. These assets and liabilities are revalued based on currency exchange rates at the end of the reporting period. To reduce our currency exchange risk, we may, if possible, arrange for a portion of our international contracts to be payable to us in local currency in amounts equal to our estimated operating costs payable in local currency, with the balance of the contract payable in U.S. dollars. The revaluation of liabilities denominated in currencies other than the U.S. dollar related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, is reported as a component of “Income tax (expense) benefit” in our Consolidated Statements of Operations. Forward-Looking Statements We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (or the Securities Act) and Section 21E of the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects: • market conditions and the effect of such conditions on our future results of operations; • • offshore exploration activity, customer capital allocation and customer spending programs; contractual obligations and future contract negotiations; 44 • commodity prices; • market outlook; • • • • • • • • • • • • • • • • • • • • • • • • • • • • • future demand for offshore drilling services and dayrates and future investment in hydrocarbons; inflation; future economic trends, including interest rates and recessionary economic conditions; operations outside the United States; geopolitical events and risks; business strategy; strategic initiatives; growth opportunities; competitive position including, without limitation, competitive rigs entering the market; expected financial position and liquidity; cash flows and contract backlog; sources and uses of and requirements for financial resources and sources of liquidity; the effects of the Chapter 11 Cases on our operations, including our relationships with employees, regulatory authorities, customers, suppliers, banks, insurance companies and other third parties, and agreements; idling drilling rigs or reactivating stacked rigs; outcomes of litigation and legal proceedings; declaration and payment of dividends; expectations regarding our plans and strategies; financing plans; debt levels and the impact of changes in the credit markets; budgets for capital and other expenditures; interest rate and foreign exchange risk and the transition away from LIBOR; business plans or financial condition of our customers, including with respect to or as a result of the COVID- 19 pandemic; duration and impacts of the COVID-19 pandemic, including new variants of the virus, lockdowns, re- openings and any other related actions taken by businesses and governments on the offshore drilling industry and our business, operations, supply chain and personnel, financial condition, results of operations, cash flows and liquidity; ESG trends, practices and related matters; tax planning and effects of the IRA; changes in tax laws and policies or adverse outcomes resulting from examination of our tax returns; contractual obligations related to our Well Control Equipment services agreement and potential exercise of the purchase option at the end of the original lease term; the MMSA and Charters with an offshore drilling company and future management and marketing services thereunder; termination of and performance of obligations under the Apache drilling contract for the Ocean Patriot; 45 • • • • • • • • • • • • • • timing and duration of required regulatory inspections for our drilling rigs and other planned downtime; process and timing for acquiring regulatory permits and approvals for our drilling operations; timing and cost of completion of capital projects; delivery dates and drilling contracts related to capital projects; plans and objectives of management; scrapping retired rigs; asset impairments and impairment evaluations; assets held for sale; our internal controls and internal control over financial reporting; performance of contracts; cybersecurity; unionization efforts; compliance with applicable laws; and availability, limits and adequacy of insurance or indemnification. These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following: • • • those described under “Risk Factors” in Item 1A; general economic and business conditions and trends, including recessions, inflation, and adverse changes in the level of international trade activity; the protracted downturn in our industry and the continuing effects thereof; • worldwide supply and demand for oil and natural gas; • • • • • • • • • • • • • changes in foreign and domestic oil and gas exploration, development and production activity; oil and natural gas price fluctuations and related market expectations; the ability of OPEC+ to set and maintain production levels and pricing, and the level of production in non- OPEC+ countries; policies of various governments regarding exploration and development of oil and gas reserves; inability to obtain contracts for our rigs that do not have contracts; inability to reactivate cold-stacked rigs; cancellation or renegotiation of contracts included in our reported contract backlog; advances in exploration and development technology; the worldwide political and military environment, including, for example, in oil-producing regions and locations where our rigs are operating or are in shipyards; casualty losses; operating hazards inherent in drilling for oil and gas offshore; the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico; industry fleet capacity; 46 • market conditions in the offshore contract drilling industry, including, without limitation, dayrates and • • • • • • • • • • • • • • • • • • • • • • • • • • utilization levels; competition; changes in foreign, political, social and economic conditions; risks of international operations, compliance with foreign laws and taxation policies and seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of equipment and assets; risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time; risks that our assumptions and analyses in the Plan are incorrect; the potential adverse effects of the Chapter 11 Cases on our liquidity, results of operations, access to capital resources or business prospects; the impact of the COVID-19 pandemic, including new variants of the virus, or future epidemics or pandemics on our business, including the potential for worker absenteeism, facility closures, work slowdowns or stoppages, supply chain disruptions, additional costs and liabilities, delays, our ability to recover costs under contracts, insurance challenges, and potential impacts on access to capital, markets and the fair value of our assets; customer or supplier bankruptcy, liquidation or other financial difficulties; the ability of customers and suppliers to meet their obligations to us and our subsidiaries; collection of receivables; foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital; risks of war, military operations, other armed hostilities, sabotage, piracy, cyber-attack, terrorist acts and embargoes, including the conflict in Ukraine; changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness; reallocation of drilling budgets away from offshore drilling in favor of other priorities such as renewable energy or land-based projects; regulatory initiatives and compliance with governmental regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use; regulations including, without limitation, compliance with and liability under environmental laws and regulations; uncertainties surrounding deepwater permitting and exploration and development activities; potential changes in accounting policies by the FASB, SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance; development and increasing adoption of alternative fuels and energy sources; customer preferences; risks of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts; cost, availability, limits and adequacy of insurance; invalidity of assumptions used in the design of our controls and procedures and the risk that material weaknesses may arise in the future; business opportunities that may be presented to and pursued or rejected by us; the results of financing efforts; adequacy and availability of our sources of liquidity; 47 • • • • risks resulting from our indebtedness; public health threats; negative publicity; and impairments of assets. The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we refer to reports of third parties that purport to describe trends or developments in energy production or drilling and exploration activity. While we believe that each of these reports is reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information. New Accounting Pronouncements For a discussion of recent accounting pronouncements that have had or are expected to have an effect on our Consolidated Financial Statements, see Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements” in Item 7 of this report. Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2022 and 2021, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions. Interest Rate Risk. We have exposure to interest rate risk on our debt instruments arising from changes in the level or volatility of interest rates. As of December 31, 2022, our variable interest rate debt included $177.5 million of outstanding borrowings under the Exit RCF, $19.4 million for the issuance of letters of credit under the Exit RCF and our $100.0 million Exit Term Loan. At this level of variable-rate debt, the impact of a 100-basis point increase in market interest rates would not have a material effect (estimated $3.0 million increase in interest expense on an annualized basis). As of December 31, 2021, our variable interest rate debt included $83.5 million of outstanding borrowings under the Exit RCF, $6.1 million for the issuance of letters of credit under the Exit RCF and our $100.0 million Exit Term Loan. At this level of variable-rate debt, the impact of a 100-basis point increase in market interest rates would not have a material effect (estimated $1.9 million increase in interest expense on an annualized basis). Our First Lien Notes have been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. 48 The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates. 49 Item 8. Financial Statements and Supplementary Data. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the stockholders and the Board of Directors of Diamond Offshore Drilling, Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income or loss, stockholders’ equity, and cash flows, for the year ended December 31, 2022 and the period from April 24, 2021 to December 31, 2021 (Successor Company operations), and the periods from January 1, 2021 to April 23, 2021 and January 1, 2020 to December 31, 2020 (Predecessor Company operations), and the related notes (collectively referred to as the "financial statements"). In our opinion, the Successor Company financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the year ended December 31, 2022 and for the period from April 24, 2021 to December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements present fairly, in all material respects, the results of its operations and its cash flows for the periods from January 1, 2021 to April 23, 2021 and January 1, 2020 to December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting. Fresh Start Reporting As discussed in Note 2 to the financial statements, on April 8, 2021, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective after the close of business on April 23, 2021. Accordingly, the accompanying financial statements have been prepared in conformity with FASB Accounting Standard Codification 852, Reorganizations, for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note 3 to the financial statements. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 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 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, 50 subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Income Taxes – Refer to Notes 1 and 16 to the financial statements Critical Audit Matter Description The Company accounts for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in the financial statements or tax returns. In each of the tax jurisdictions, the Company recognized a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. The deferred tax liability balance was $0.7 million as of December 31, 2022, and income tax benefit (expense) was $2.4 million for the year ended December 31, 2022. In several of the jurisdictions in which the Company operates, certain wholly-owned subsidiaries entered into agreements with other wholly-owned subsidiaries to provide specialized services and equipment. The Company applied transfer pricing methodologies to determine the amount to be charged for providing the services and equipment and utilized outside consultants to assist in the development of such transfer pricing methodologies. Each jurisdiction enacts laws, which, in many cases, allows for alternative transfer pricing methodologies, which may differ from the Company’s selected methodologies. Alternative transfer pricing methodologies, if applied, could result in different chargeable amounts. Given the multiple jurisdictions in which the Company files tax returns and the complexity of the tax laws and regulations, and transfer pricing methodologies applied to wholly-owned subsidiary transactions, auditing management’s estimates of income taxes in foreign jurisdictions required a high degree of auditor judgment and an increased extent of effort, including the use of our tax specialists and audit teams in the local jurisdiction knowledgeable of the tax laws of the applicable country. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the Company’s application of transfer pricing methodologies, included the following, among others: • We evaluated the appropriateness and consistency of management’s methods and assumptions used in the application of its transfer pricing methodology. • We involved transfer pricing specialists to evaluate the reasonableness of transfer pricing methodologies utilized by the Company. • We tested the accuracy of transfer prices by recalculating the prices in accordance with the chosen methodology. • With the assistance of our income tax specialists and audit teams in the local jurisdiction knowledgeable of the tax laws of the applicable country, we evaluated management’s assertions with respect to the Company’s entitlement to the economic benefits associated with the tax positions resulting from the application of transfer pricing methodology. /s/ DELOITTE & TOUCHE LLP Houston, Texas February 28, 2023 We have served as the Company’s auditor since 1989. 51 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the stockholders and the Board of Directors of Diamond Offshore Drilling, Inc. Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 28, 2023, expressed an unqualified opinion on those consolidated financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ DELOITTE & TOUCHE LLP Houston, Texas February 28, 2023 52 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except per share data) ASSETS Current assets: Cash and cash equivalents Restricted cash Accounts receivable Less: allowance for credit losses Accounts receivable, net Prepaid expenses and other current assets Asset held for sale Total current assets Drilling and other property and equipment, net of accumulated depreciation Other assets Total assets LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable Accrued liabilities Taxes payable Current finance lease liabilities Total current liabilities Long-term debt Noncurrent finance lease liabilities Deferred tax liability Other liabilities Commitments and contingencies (Note 12) Total liabilities Stockholders’ equity: Preferred stock (par value $0.0001, 50,000 shares authorized, none issued and outstanding) Common stock (par value $0.0001, 750,000 shares authorized; 101,884 shares issued and 101,320 shares outstanding at December 31, 2022; 100,075 shares issued and outstanding at December 31, 2021) Additional paid-in capital Treasury stock Accumulated deficit Total stockholders’ equity Total liabilities and stockholders’ equity December 31, 2022 2021 $ $ $ 63,041 34,293 177,675 (5,622) 172,053 48,695 — 318,082 1,141,908 67,966 1,527,956 47,647 166,785 30,264 16,965 261,661 360,644 131,393 700 93,888 38,388 24,341 151,917 (5,582) 146,335 61,440 1,000 271,504 1,175,895 84,041 1,531,440 38,661 143,736 34,500 15,865 232,762 266,241 148,358 1,626 114,748 848,286 763,735 — — 10 964,467 (4,252) (280,555) 679,670 1,527,956 $ 10 945,039 — (177,344) 767,705 1,531,440 $ $ $ $ The accompanying notes are an integral part of the consolidated financial statements. 53 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share data) Revenues: Contract drilling Revenues related to reimbursable expenses Total revenues Operating expenses: Contract drilling, excluding depreciation Reimbursable expenses Depreciation General and administrative Impairment of assets Restructuring and separation costs Gain on disposition of assets Total operating expenses Operating loss Other income (expense): Interest income Interest expense (excludes $35,390 and $98,027 of contractual interest expense on debt subject to compromise for the period from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, respectively) Foreign currency transaction loss Reorganization items, net Other, net Loss before income tax benefit (expense) Income tax benefit (expense) Net loss Loss per share, Basic and Diluted Weighted-average shares outstanding, Basic and Diluted Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through Year Ended December 31, April 23, 2021 2020 $ 724,744 $ 116,534 841,278 465,328 90,738 556,066 $ 153,364 $ 16,015 169,379 692,753 40,934 733,687 620,982 114,962 103,478 70,196 — — (4,895) 904,723 (63,445) 364,539 89,284 68,504 53,494 132,449 — (1,024) 707,246 (151,180) 181,626 15,477 92,758 15,036 197,027 — (5,486) 496,438 (327,059) 618,553 38,900 320,085 56,925 842,016 17,724 (7,375) 1,886,828 (1,153,141) 18 3 30 484 (40,423) (3,023) — 1,267 (105,606) 2,395 (26,180) (997) (8,088) 10,752 (175,690) (1,654) $ (103,211) $ (177,344) (1.77) $ (1.03) $ (34,827) (172) (1,639,763) 398 (2,001,393) 39,404 (42,585) (4,498) (76,910) 560 (1,276,090) 21,186 $ (1,961,989) $(1,254,904) (9.09) $ (14.21) $ 100,561 100,071 138,054 137,996 The accompanying notes are an integral part of the consolidated financial statements. 54 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME OR LOSS (In thousands) Net loss Other comprehensive losses, net of tax: Derivative financial instruments: Reclassification adjustment for loss included in net loss Total other comprehensive gain Comprehensive loss Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through Year Ended December 31, April 23, 2021 2020 $ (103,211) $ (177,344) $(1,961,989) $(1,254,904) 18 18 $ (103,211) $ (177,344) $(1,961,989) $(1,254,886) — — — — — — The accompanying notes are an integral part of the consolidated financial statements. 55 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (In thousands) Common Stock Shares Amount Additional Paid-In Capital Retained Earnings Accumulated Other (Accumulated Comprehensive Gains (Losses) Deficit) Treasury Stock Shares Amount Total Stockholders’ Equity 144,782 — $ 1,448 — $ 2,024,347 — $ 1,412,201 (1,254,904) $ (18) — $ 7,078 — (205,768) $ — 3,232,210 (1,254,904) January 1, 2020 (Predecessor) Net loss Stock-based compensation, net of tax Net gain on derivative financial instruments December 31, 2020 Net loss Cancellation of Predecessor equity April 23, 2021 (Predecessor) 482 — 145,264 — 5 5,632 — — 1,453 — — 2,029,979 — — 157,297 (1,961,989) (145,264) (1,453) (2,029,979) 1,804,692 — $ — $ — $ — $ Issuance of Successor equity April 24, 2021 (Successor) Net loss Stock-based compensation, net of tax December 31, 2021 Net loss Stock-based compensation, net of tax December 31, 2022 (Successor) $ $ 100,000 100,000 — 75 100,075 — 1,245 $ $ 10 10 — — 10 — — $ $ 934,800 934,800 — 10,239 945,039 — 19,428 — — $ (177,344) — (177,344) $ (103,211) 101,320 $ 10 $ 964,467 $ (280,555) $ — 18 — — — — — — — — — — 132 — 7,210 — (395) 5,242 — (206,163) — 18 1,982,566 (1,961,989) (7,210) 206,163 — $ — $ (20,577) — — — $ — — — $ — — — $ — — — $ — 934,810 934,810 (177,344) 10,239 767,705 (103,211) 564 (4,252) 15,176 564 $ (4,252) $ 679,670 The accompanying notes are an integral part of the consolidated financial statements. 56 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through April 23, 2021 Year Ended December 31, 2020 $ (103,211) $ (177,344) $ (1,961,989) $(1,254,904) 103,478 — — (4,895) 479 20,159 (36,292) 1,694 (1,594) 62 17,479 (2,950) 115 2,194 (25,718) 2,028 55,006 (19,170) 8,864 (60,023) 5,959 1,670 — (52,394) — 94,000 — — — (15,865) 78,135 34,605 68,504 132,449 — (1,024) (3,482) 10,766 48,293 (1,418) (13,081) 119 6,030 361 (2,092) 1,579 (16,984) 305 (40,133) 6,056 18,904 (42,812) 1,053 — — (41,759) — 50,000 (70,000) — — (9,845) (29,845) (52,700) 92,758 197,027 1,587,392 (5,486) (35,894) — 10,617 (742) (12,034) 475 — 2,685 (371) 2,683 2,108 (2,791) 29,302 (5,804) (100,064) (49,119) 7,484 — — (41,635) (442,034) 200,000 — 75,000 (6,218) — (173,252) (314,951) 320,085 842,016 22,106 (7,375) (19,228) 5,637 8,823 3,444 1,960 (4,256) (18,262) (7,950) (2,279) 3,321 114,329 6,334 (14,143) 8,721 8,379 (189,528) 13,333 — 5,915 (170,280) 436,000 — — — — — 436,000 274,099 62,729 97,334 $ 115,429 62,729 $ 430,380 115,429 $ 156,281 430,380 $ Operating activities: Net loss Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation Loss on impairment of assets Reorganization items, net (Gain) loss on disposition of assets Deferred tax provision Stock-based compensation expense Contract liabilities, net Contract assets, net Deferred contract costs, net Long-term employee remuneration programs Collateral deposits Other assets, noncurrent Other liabilities, noncurrent Other Changes in operating assets and liabilities: Accounts receivable Prepaid expenses and other current assets Accounts payable and accrued liabilities Taxes payable Net cash provided by (used in) operating activities Investing activities: Capital expenditures Proceeds from disposition of assets, net of disposal costs Deposits on asset sales Proceeds from sale of foreign bonds Net cash used in investing activities Financing activities: (Repayments of) borrowings under revolving credit facility Borrowings on exit facilities Repayments on exit facilities Issuance of exit notes Debt issuance costs and arrangement fees Principal payments of finance lease liabilities Net cash provided by (used in) financing activities Net change in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash, beginning of period Cash, cash equivalents and restricted cash, end of period The accompanying notes are an integral part of the consolidated financial statements. 57 DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. General Information Diamond Offshore Drilling, Inc. provides contract drilling services to the energy industry around the globe with a fleet of 14 offshore drilling rigs, consisting of four owned drillships, eight owned semisubmersible rigs and two managed rigs. Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these Consolidated Financial Statements and footnotes as the “Successor” for periods subsequent to April 23, 2021 and to the pre-emergence company as the “Predecessor” for periods on or prior to April 23, 2021. This delineation between Predecessor periods and Successor periods is shown in the Consolidated Financial Statements, certain tables within the footnotes to the Consolidated Financial Statements and other parts of this Annual Report on Form 10-K through the use of a black line, calling out the lack of comparability between periods. Principles of Consolidation Our Consolidated Financial Statements include the accounts of Diamond Offshore Drilling, Inc. and our wholly- owned subsidiaries after elimination of intercompany transactions and balances. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States (or U.S.), or GAAP, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated. Cash and Cash Equivalents We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. The effect of exchange rate changes on cash balances held in foreign currencies was not material for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021. Asset Held for Sale We reported the $1.0 million carrying value of the Ocean Valor, as “Asset held for sale” in our Successor Consolidated Balance Sheet at December 31, 2021. The rig was sold in February 2022 at a net pre-tax gain of approximately $4.0 million. Drilling and Other Property and Equipment We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. 58 Changes in these judgments, assumptions and estimates could produce results that differ from those reported. During the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, we capitalized $69.1 million, $22.0 million and $59.9 million, respectively, in replacements and betterments of our drilling fleet. Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in- progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are reported in our Consolidated Statements of Operations as “(Gain) loss on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from 3 to 30 years. Impairment of Long-Lived Assets We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, a change in the economic useful life of a rig, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project, reactivation or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following: • • • • • • • • dayrate by rig; utilization rate by rig if active, warm-stacked or cold-stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates); the per day operating cost for each rig if active, warm-stacked or cold-stacked; the estimated annual cost for rig replacements and/or enhancement programs; the estimated maintenance and inspection or other reactivation costs associated with a rig returning to work; the remaining economic useful life of a rig; salvage value for each rig; and estimated proceeds that may be received on disposition of each rig. Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability- weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability. The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment. Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the 59 measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancellations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, capital expenditures required due to advances in offshore drilling technology, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. See Note 5 “Asset Impairments.” Survey Costs Concurrent with emergence from bankruptcy, the Successor entity adopted a new policy providing for the deferral and amortization of costs associated with planned periodic inspections of its drilling rigs (or vessels) to ensure compliance with applicable regulations and maintain certifications for vessels with classification societies that typically occur on five-year or two-and-one-half year intervals. These costs include mobilization of the vessel into the shipyard, drydocking, support services while in shipyard and the associated survey or inspection costs necessary to maintain class certifications. These recertification costs are typically incurred while the vessel is in drydock and may be performed concurrent with other vessel maintenance and improvement activities. Costs related to the recertification of vessels are deferred and amortized over the survey interval on a straight-line basis. Maintenance costs incurred at the time of the recertification drydocking, which are not related to the recertification of the vessel are expensed as incurred. Costs for vessel improvements which either extend the vessel’s useful life or increase the vessel's functionality are capitalized and depreciated. The Predecessor’s previous policy was to expense vessel recertification costs in the period incurred. For the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021, we deferred $3.3 million and $0.9 million, respectively, in survey costs. At December 31, 2022 and 2021, deferred survey costs of $0.8 million and $0.5 million, respectively, were reported in “Prepaid expenses and other current assets” and $2.5 million and $0.2 million, respectively, were reported in “Other assets” in our Successor Consolidated Balance Sheets. We amortized $0.7 million and $0.2 million in deferred survey costs as “Contract drilling, excluding depreciation” in the Successor’s Consolidated Statements of Operations for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021. Lease Accounting and Revenue Recognition Financial Accounting Standards Board (or FASB) Accounting Standards Update (or ASU), No. 2016-02, Leases (Topic 842) (ASU 2016-02), requires lessees to recognize a right of use asset and a lease liability on the balance sheet for most leases. Upon adoption of ASU 2016-02, we concluded that our drilling contracts contain a lease component for the use of our drilling rigs based on the updated definition of a lease. However, ASU 2016-02 provides for a practical expedient for lessors whereby, under certain circumstances, the lessor may combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. We have determined that our current drilling contracts qualify for this practical expedient and have combined the lease and service components of our standard drilling contracts. We continue to account for the combined component under FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and its related amendments (collectively referred to as Topic 606). Fair Value of Financial Instruments We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. See Note 9 “Financial Instruments and Fair Value Disclosures.” Debt Issuance Costs Deferred costs associated with our credit facility are presented in “Other assets” in the Successor's Consolidated Balance Sheets at December 31, 2022 and 2021 and amortized as interest expense over the respective terms of the credit facility. Deferred costs associated with our other long-term debt are presented in the Successor's Consolidated 60 Balance Sheets at December 31, 2022 and 2021 as a reduction in the related long-term debt and are amortized over the respective terms of the related debt as interest expense. See Note 2 “Chapter 11 Proceedings” and Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt” for a discussion of deferred arrangement fees associated with our Successor and Predecessor credit facilities and long-term debt. Income Taxes We account for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. Deferred tax assets and liabilities are classified as noncurrent in a classified statement of financial position. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit. We record both interest and penalties related to accrued uncertain tax positions in “Income tax benefit (expense)” in our Consolidated Statements of Operations. Liabilities for uncertain tax positions, including any interest and penalties, are denominated in the currency of the related tax jurisdiction and are revalued for changes in currency exchange rates. The revaluation of such liabilities for uncertain tax positions is reported in “Income tax benefit (expense)” in our Consolidated Statements of Operations. See Note 16 “Income Taxes.” Comprehensive Loss Comprehensive (loss) income is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive loss for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 includes net losses and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges. Foreign Currency Our functional currency is the U.S. dollar. Transactions incurred in currencies other than the U.S. dollar are subject to gains or losses due to fluctuations in those currencies. We report foreign currency transaction gains and losses as “Foreign currency transaction loss” in our Consolidated Statements of Operations. The revaluation of assets and liabilities related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, including any interest and/or penalties, is reported in “Income tax (expense) benefit” in our Consolidated Statements of Operations. 2. Chapter 11 Proceedings Chapter 11 Cases On April 26, 2020 (or the Petition Date), Diamond Offshore Drilling, Inc. (or the Company) and certain of its direct and indirect subsidiaries (which we refer to, together with the Company, as the Debtors) filed voluntary petitions (or the Chapter 11 Cases) for relief under chapter 11 (or Chapter 11) of title 11 of the United States Code (or the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas (or the Bankruptcy Court). The Chapter 11 Cases were jointly administered under the caption In re Diamond Offshore Drilling, Inc., et al., Case No. 20-32307 (DRJ). 61 On January 22, 2021, the Debtors entered into a Plan Support Agreement (or the PSA) among the Debtors, certain holders of the Company’s then-existing 5.70% Senior Notes due 2039, 3.45% Senior Notes due 2023, 4.875% Senior Notes due 2043 and 7.875% Senior Notes due 2025 (collectively, the Senior Notes) party thereto and certain holders of claims (collectively, the RCF Claims) under the Company’s then-existing $950.0 million syndicated revolving credit facility (or RCF). Concurrently, the Debtors entered into the Backstop Agreement (as defined in the PSA) with certain holders of Senior Notes and entered into the Commitment Letter (as defined in the PSA) with certain holders of RCF Claims to provide exit financing upon emergence from bankruptcy. The Debtors filed a joint Chapter 11 plan of reorganization with the Bankruptcy Court on January 22, 2021, which was subsequently amended on February 24, 2021 and February 26, 2021 (or the Plan). On March 23, 2021, the Debtors filed the plan supplement for the Plan with the Bankruptcy Court, which was subsequently amended on April 6, 2021 and April 22, 2021 (or the Plan Supplement). Chapter 11 Emergence On April 8, 2021, the Bankruptcy Court entered an order confirming the Plan (or the Confirmation Order). On April 23, 2021 (or the Effective Date), all conditions precedent to the Plan were satisfied, the Plan became effective in accordance with its terms, and the Debtors emerged from Chapter 11 reorganization. New Diamond Common Shares and New Warrants On the Effective Date, in connection with the effectiveness of, and pursuant to the terms of, the Plan and the Confirmation Order, the Company’s common stock outstanding immediately before the Effective Date was canceled. The new organizational documents of the Reorganized Company (as defined below) became effective, authorizing the issuance of shares of common stock representing 100% of the equity interests in the Reorganized Company (or the New Diamond Common Shares). Pursuant to the Warrant Agreement (as defined below), the Emergence Warrants (as defined below) were issued by the Company to holders of existing shares of common stock in the amounts, and on the terms, set forth in the Plan and the Plan Supplement. Thus, the Company, as reorganized on the Effective Date in accordance with the Plan (or the Reorganized Company), issued the New Diamond Common Shares and the Emergence Warrants, and the 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (or the First Lien Notes) were issued by Diamond Foreign Asset Company (or DFAC), a Cayman Islands exempted company limited by shares, and Diamond Finance, LLC (or DFLLC), a newly-formed wholly-owned subsidiary of DFAC (collectively, the New Capital). The New Capital issued pursuant to the Plan was issued in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (or the Securities Act), provided by section 1145 of the Bankruptcy Code and, to the extent such exemption was unavailable, was issued in reliance on the exemption provided by section 4(a)(2) of the Securities Act or another applicable exemption. The new organizational documents authorized the Company to issue two classes of stock designated, respectively, common stock and preferred stock. The total number of shares of capital stock that the Company shall have authority to issue is 800 million consisting of 750 million shares of common stock, having a par value of $0.0001 per share (or Common Stock), and 50 million shares of preferred stock, having a par value of $0.0001 per share. On the Effective Date, pursuant to the Plan: • • • 70.0 million New Diamond Common Shares were transferred pro rata to holders of Senior Notes Claims (as defined in the Plan) in exchange for the cancellation of the Senior Notes; 30.0 million New Diamond Common Shares were transferred pro rata to holders of Senior Notes Claims in exchange for providing $114.7 million of new-money commitments to the Debtors pursuant to the Rights Offerings, the Private Placement, and the Backstop Commitments (each as defined in the Backstop Agreement); and 7.5 million Emergence Warrants were issued to the holders of Existing Parent Equity Interests (as defined in the Plan). As of the Effective Date, 100.0 million New Diamond Common Shares were issued and outstanding. 62 On the Effective Date and pursuant to the Plan, the Company entered into a Warrant Agreement (or the Warrant Agreement) with Computershare Inc., a Delaware corporation, and Computershare Trust Company, N.A., a federally chartered trust company, as warrant agent, which provides for the issuance of an aggregate of 7.5 million five-year warrants with no Black Scholes protection (or the Emergence Warrants). The Emergence Warrants have an exercise period of five years and are exercisable into 7% of the New Diamond Common Shares measured at the time of the exercise, subject to dilution by the MIP Equity Shares (as defined in the Plan). The Emergence Warrants are initially exercisable for one New Diamond Common Share per Emergence Warrant at an exercise price of $29.22 per Emergence Warrant (as may be adjusted from time to time pursuant to the Warrant Agreement). Pursuant to the Warrant Agreement, no holder of Emergence Warrants shall have or exercise any rights held by holders of New Diamond Common Shares solely by virtue thereof as a holder of Emergence Warrants, including the right to vote or to receive dividends and other distributions as a holder of New Diamond Common Shares. Registration Rights Agreement On the Effective Date, the Company entered into a registration rights agreement (or the Registration Rights Agreement) with certain parties who received New Diamond Common Shares under the Plan (or the RRA Shareholders). The RRA Shareholders exercised their right to require the Company to file a shelf registration statement and on June 22, 2021, the Company filed a registration statement on Form S-1, which was later converted to a registration statement on Form S-3, to register 20,229,065 shares of Common Stock owned by the RRA Shareholders. The Company will not receive any proceeds from the sale of these shares and will bear all expenses associated with the registrations of such shares. The registration statement went effective on June 17, 2022. New Debt at Emergence On the Effective Date, pursuant to the terms of the Plan, the Company and DFAC entered into the following debt instruments: • • • • a senior secured revolving credit agreement (or the Exit Revolving Credit Agreement), which provides for a $400.0 million senior secured revolving credit facility (or the Exit RCF); a senior secured term loan credit agreement (or the Exit Term Loan Credit Agreement), which provides for a $100.0 million senior secured term loan credit facility (or the Exit Term Loan Credit Facility and, together with the Exit RCF, the Exit Facilities), which is scheduled to mature on April 22, 2027 under which $100.0 million was drawn on the Effective Date (or the Exit Term Loans); an indenture (or the First Lien Notes Indenture), pursuant to which approximately $85.3 million in aggregate principal amount of First Lien Notes maturing on April 22, 2027 were issued on the Effective Date; and approximately $39.7 million in the form of delayed draw note commitments that may be issued as additional First Lien Notes after the Effective Date (or the Last Out Incremental Debt), none of which had been issued as of December 31, 2022. See Note 11 “Prepetition Revolving Credit Facility, Senior Notes and Exit Debt.” Claims Treatment Under the Plan In accordance with the Plan, holders of claims against and interests in the Debtors received the following treatment on the Effective Date, or as soon as reasonably practicable thereafter: • Other Secured Claims. Except to the extent that such holder agreed to a less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for such Other Secured Claim (as defined in the Plan), each such holder received (i) payment in full in cash or (ii) such other treatment so as to render such holder’s claim unimpaired. • Other Priority Claims. Except to the extent that such holder agreed to a less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for such claim each holder of an 63 Allowed Other Priority Claim (as defined in the Plan) received (i) payment in cash of the unpaid portion of its claim or (ii) other treatment consistent with the provisions of section 1129(a)(9) of the Bankruptcy Code. • RCF Claims. Except to the extent that such holder agreed to a less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for each RCF Claim (as defined in the Plan), each holder of an Allowed RCF Claim (as defined in the Plan) received (A) first, its pro rata share calculated as a percentage of all holders in such class that elected to participate in the Exit RCF of the RCF Cash Paydown (as defined in the Plan); (B) second, to the extent such holder’s RCF Claims were not satisfied in full after the application of the RCF Cash Paydown, its Participating RCF Lender Share (as defined in the Plan) of up to $100 million of funded loans under the Exit RCF; and (C) third, to the extent such holder’s RCF Claims were not satisfied in full after the application of the RCF Cash Paydown and the allocation of funded loans under the Exit RCF, a share of $200 million (less the amount of aggregate funded loans under the Exit RCF on the Effective Date) of the Exit Term Loan Credit Facility that was equal to the remaining unsatisfied amount of such holder’s RCF Claims. • Senior Notes Claims. Except to the extent that such holder agreed to a less favorable treatment, in full and final satisfaction, settlement, release and discharge of, and in exchange for such Senior Notes Claims (as defined in the Plan), each holder of an Allowed Senior Notes Claim (as defined in the Plan) received its pro rata share of 70.00% of the New Diamond Common Shares, subject to dilution by the Emergence Warrants and the MIP Equity Shares. • General Unsecured Claims. Except to the extent that such holder agreed to a less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for such General Unsecured Claims (as defined in the Plan), each holder of an Allowed General Unsecured Claim (as defined in the Plan) received (i) payment in full in cash (inclusive of post-petition interest); (ii) Reinstatement (as defined in the Plan); or (iii) such other treatment sufficient to render such claims unimpaired. • • • Existing Parent Equity Interests. Each holder of an Allowed Existing Parent Equity Interest (as defined in the Plan) received its pro rata share of the Emergence Warrants, subject to dilution by the MIP Equity Shares. Intercompany Claims. All Intercompany Claims (as defined in the Plan) were adjusted, Reinstated (as defined in the Plan), or discharged at the Debtors’ discretion. Intercompany Interests. All Intercompany Interests (as defined in the Plan) were (i) canceled (or otherwise eliminated) and received no distribution under the Plan or (ii) Reinstated at the Debtors’ option. Chapter 11 Accounting We have prepared our Consolidated Financial Statements as if we were a going concern and in accordance with FASB Accounting Standards Codification (or ASC) Topic No. 852 – Reorganizations (or ASC 852). Prepetition Restructuring Charges. We have reported legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date, as “Restructuring and separation costs” in our Consolidated Statements of Operations for the Predecessor year ended December 31, 2020. See Note 15 "Restructuring and Separation Costs." Reorganization Items. Expenditures, gains and losses that are realized or incurred by the Debtors subsequent to the Petition Date and as a direct result of the Chapter 11 Cases are reported as “Reorganization items, net” in our Consolidated Statements of Operations for the Successor period from April 24, 2021, through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020. These costs include legal and other professional advisory service fees pertaining to the Chapter 11 Cases and all adjustments made to the carrying amount of certain prepetition liabilities reflecting claims that were expected to be allowed by the Bankruptcy Court. 64 The following tables provide information about reorganization items incurred during the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 (in thousands): Successor Period from April 24, 2021 through December 31, 2021 Professional fees Fresh start valuation adjustments Net gain on settlement of liabilities subject to compromise Accrued backstop commitment premium Write-off of predecessor directors and officers tail insurance policy Write-off of debt issuance costs Other Total reorganization items, net $ $ 8,088 — — — — — — 8,088 Predecessor Period from January 1, 2021 through April 23, 2021 $ 51,084 $ 2,699,422 (1,129,892) 10,424 6,932 1,793 — $ 1,639,763 $ Year Ended December 31, 2020 53,517 — — — — 27,552 (4,159) 76,910 Payments of $36.2 million, $37.6 million and $40.3 million related to professional fees and vendor cancellation costs have been presented as cash outflows from operating activities in our Consolidated Statements of Cash Flows for the Successor period from April 24, 2021 to December 31, 2021 and the Predecessor periods from January 1, 2021 to April 23 2021 and the year ended December 31, 2020. See Note 6 “Supplemental Financial Information — Consolidated Statements of Cash Flows Information.” Liabilities Subject to Compromise. At April 23, 2021, “Liabilities subject to compromise” was comprised of the aggregate principal balance of our Senior Notes of $2.0 billion and the corresponding accrued interest of $44.9 million, as all other claims were to be paid in full and were unimpaired per the Plan. Upon commencement of the Chapter 11 Cases on April 26, 2020, we ceased accruing interest on our Senior Notes and borrowings under our RCF. However, due to provisions in the PSA signed in January 2021 and other orders of the Bankruptcy Court, we resumed recognizing interest on our outstanding borrowings under the RCF and also recorded the unpaid post-petition interest not previously recognized. As a result, during the Predecessor period from January 1, 2021 through April 23, 2021, we accrued interest expense of $35.3 million for the period from April 26, 2020 through March 31, 2021, inclusive of a $23.4 million catch-up adjustment for the period from April 26, 2020 through December 31, 2020, and have reported such amount as “Interest expense” in our Consolidated Statements of Operations for the Predecessor period from January 1, 2021 through April 23, 2021. 3. Fresh Start Accounting Fresh Start Accounting Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with ASC 852, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. The criteria requiring fresh start accounting are: (i) the holders of the then-existing voting shares of the Predecessor (or legacy entity prior to the Effective Date) received less than 50 percent of the new voting shares of the Successor outstanding upon emergence from bankruptcy, and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. In addition, as a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the period after April 23, 2021 will not be comparable with the financial statements prior to and including April 23, 2021. References to “Successor” refer to the Company and its financial position and results of operations after the Effective Date (or for the year ended December 31, 2022 and for the period 65 from April 24, 2021 to December 31, 2021). References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Effective Date (or from January 1, 2021 to April 23, 2021). Reorganization Value Reorganization value approximates the fair value of the Successor’s total assets and the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values (except for deferred income taxes) in conformity with FASB ASC Topic 805, Business Combinations, and FASB ASC Topic 820, Fair Value Measurement. The amount of deferred taxes was determined in accordance with FASB ASC Topic 740, Income Taxes (or ASC 740). The Company’s reorganization value is derived from management projections and the valuation models determined by the Company’s financial advisors in setting an estimated range of enterprise values. Enterprise value represents the estimated fair value of an entity’s shareholders’ equity plus long-term debt and other interest-bearing liabilities less unrestricted cash and cash equivalents. The Company’s bankruptcy financial advisor did not contemplate any value within the selected estimated ranges of enterprise value for deferred tax assets or uncertain tax positions due to various unknown factors at the time the enterprise value assumptions were produced. At emergence, the resulting values calculated for the deferred tax asset and uncertain tax liabilities have a net accretive impact on the value of the Successor equity. As set forth in the disclosure statement approved by the Bankruptcy Court, the valuation analysis resulted in an enterprise value between $805.0 million and $1,520.0 million with a selected mid-point of $1,130.0 million. For U.S. GAAP purposes, we valued the Successor’s individual assets, liabilities, and equity instruments and determined that the value of the enterprise was $1,130.0 million as of the Effective Date, which fell in line within the selected mid-point of the forecasted enterprise value ranges approved by the Bankruptcy Court. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process. The following table reconciles the enterprise value to the estimated fair value of the Successor’s equity as of the Effective Date (in thousands): Enterprise value Plus: Cash and cash equivalents Plus: Deferred tax assets and uncertain tax positions Less: Fair value of debt Fair value of Successor equity April 23, 2021 1,130,000 79,982 10,810 (285,982) 934,810 $ $ The following table reconciles enterprise value to the reorganization value of the Successor (i.e., value of the reconstituted entity) as of the Effective Date (in thousands): Enterprise value Plus: Cash and cash equivalents Plus: Non-interest bearing current liabilities Plus: Non-interest bearing non-current liabilities Plus: Deferred tax assets and uncertain tax positions Reorganization value of Successor assets April 23, 2021 1,130,000 79,982 225,637 276,418 10,810 1,722,847 $ $ 66 With the assistance of third-party valuation advisors, we determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) market approach using selling prices of similar assets and (iii) cost approach. The enterprise value and corresponding equity value are dependent upon achieving future financial results set forth in our valuations, as well as the realization of certain other assumptions. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, the estimates, assumptions, valuations or financial projections may not be realized and actual results could vary materially. Valuation Process Under the application of fresh start accounting and with the assistance of valuation experts, we conducted an analysis of the consolidated balance sheet to determine if any of the Company’s net assets would require a fair value adjustment as of the Effective Date. The results of our analysis indicated that our principal assets, which include drilling and other property and equipment; warehouse stock and fuel inventory; leases; long-term debt and warrants would require a fair value adjustment on the Effective Date. The rest of the Company’s net assets were determined to have carrying values that approximated fair value on the Effective Date with the exception of certain contract assets and liabilities which were written off. Deferred tax assets and uncertain tax positions were determined in accordance with ASC 740 after considering the tax effects of the reorganization and the newly established fair values of the Successor. Further details regarding the valuation process are described below. Drilling and Other Property and Equipment. The valuation of our offshore drilling units and other related tangible assets was determined by using a combination of (1) the discounted free cash flows expected to be generated from our drilling assets over their remaining useful lives and (2) the cost to replace our drilling assets, as adjusted by the current market for similar offshore drilling assets. Assumptions used in our assessment of the discounted free cash flows included, but were not limited to, the expected operating dayrates, operating costs, utilization rates, tax rates, capital expenditures, working capital requirements and estimated economic useful lives. The cash flows were discounted at a market participant weighted average cost of capital, which was derived from a blend of market participant after-tax cost of debt and market participant cost of equity, and computed using public share price information for similar offshore drilling market participants, certain U.S. Treasury rates, and certain risk premiums specific to the assets of the Company. For rigs where an active secondary market exists or that were expected to be scrapped, the market approach was used to estimate the fair value of the assets which involved gathering and analyzing recent market data of comparable assets. The fair value of land assets was estimated using a sales comparison method of the market approach which was based on third party databases identifying listings of recent sales, discussions held with local market participants and comparable properties within relevant market areas. Buildings and improvements and rig spare equipment were valued using a cost approach, in which we estimated the replacement cost of the assets and applied adjustments for physical depreciation and obsolescence, where applicable, to arrive at a fair value. The remaining property and equipment was valued by applying an economic obsolescence adjustment of 80% to the carrying value based on the implied economic obsolescence observed from the offshore rig fleet. The fair value of the blow out preventer (or BOP) lease right-of-use (or ROU) asset was also included within the “Drilling and Other Property and Equipment” value. The valuation methodology related to the BOP lease ROU asset is discussed in the “Leases” section below. Warehouse Stock and Fuel Inventory. The fair value of warehouse stock was determined by applying an economic obsolescence adjustment of 80% to the carrying value based on the implied economic obsolescence observed from the offshore rig fleet. The fair value of fuel inventory was included at carrying value, which was representative of the price per gallon on the date of emergence from bankruptcy. These balances were included within the “Prepaid expenses and other current assets” caption. Leases. The fair value of leases was estimated using the present value of the remaining lease payments discounted at a weighted average incremental borrowing rate (or IBR) of 6.7% for the emergent entity on the date of 67 remeasurement (i.e., the Effective Date) with a further adjustment to the ROU assets for prepaid rent which was akin to an off-market term. Long-term Debt. The fair values of the Exit RCF and the Exit Term Loans were based on relevant market data as of the Effective Date and the terms of each respective instrument. Considering the interest rates were consistent with a range of comparable market yields (with considerations for term and seniority), the fair values of the Exit RCF and Exit Term Loans were consistent with the corresponding principal amounts outstanding as of the Effective Date. Thus, the values were reflected at par value. The fair value of the First Lien Notes was based on relevant market data as of the Effective Date, the contractual terms including the pre-payment terms, and a yield-to-worst analysis as of the Effective Date, which resulted in an estimated fair value of 101.0% of par as of the Effective Date. Warrants. The fair value of the Emergence Warrants issued upon the Effective Date was estimated using the Black-Scholes-Merton option pricing model. The Black-Scholes-Merton model is an option pricing model used to estimate the fair value of options and warrants based on the following input assumptions: stock price, strike price, term, risk-free rate, volatility, and dividend yield. In using the Black-Scholes-Merton option pricing model to estimate the fair value of the warrants, the following assumptions were used: the stock price assumption was based on the value per share of Common Stock from the equity value as of the Effective Date and the equity capital structure; for the strike price assumption, the contractual strike price of $29.22 was used; the term assumption was based on the contractual term of the Emergence Warrants of five years as of the Effective Date; the expected volatility assumption of 70% was estimated using market data for certain similar publicly traded entities with considerations for differences in size and leverage of the Company versus the similar publicly traded entities; and the risk-free rate assumption of 0.83% was based on United States Constant Maturity Treasury rates as of the Effective Date. 68 Consolidated Balance Sheet The following illustrates the effects on the Company’s Consolidated Balance Sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants. Unless otherwise indicated, dollar amounts are stated in thousands. ASSETS Current assets: Cash and cash equivalents Restricted cash Accounts receivable Less: allowance for credit losses Accounts receivable, net Prepaid expenses and other current assets Assets held for sale Total current assets Drilling and other property and equipment, net of accumulated depreciation Other assets Deferred tax asset Total assets LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable Accrued liabilities Short-term debt Finance lease right of use liabilities, current Taxes payable Total current liabilities Deferred tax liability Other liabilities Finance lease right of use liabilities, noncurrent Long-term debt Total liabilities not subject to compromise Liabilities subject to compromise Stockholders’ equity: Predecessor preferred stock Predecessor common stock Predecessor additional paid-in capital Predecessor treasury stock Successor preferred stock Successor common stock Successor additional paid-in capital Successor treasury stock Accumulated deficit Total stockholders’ equity Total liabilities and stockholders’ equity April 23, 2021 Transaction Accounting Predecessor Reorganization Adjustments Fresh Start Adjustments Successor $ 333,699 $ 3,274 134,104 (5,555) 128,549 108,594 1,000 575,116 (253,717) (a) $ 32,173 (b) — — — (15,484) (c) — (237,028) — $ — 802 (r) — 802 (34,455) (s) — (33,653) 79,982 35,447 134,906 (5,555) 129,351 58,655 1,000 304,435 3,892,150 179,783 — $ 4,647,049 $ 182,985 (d) (112,454) (e) — (166,497) (2,720,485) (t) 1,354,650 57,047 6,716 $1,722,848 (10,282)(u) 6,716 (r) $ (2,757,704) (996) (f) $ — $ (67,125) (g) (442,034) (h) 15,148 (i) — (495,007) 3,869 (j) (90,098) (k) 158,919 (l) 285,982 (m) (136,335) (2,044,877) (n) — (1,453) (o) (2,029,978) (o) 206,163 (o) — 10 (p) 934,800 (p) — (55,961) (v) — — — (55,961) (34,447)(w) 7,518 (r) (9,837) (x) — — (92,727) — 65,401 123,055 — 15,148 22,034 225,638 — 117,499 158,919 285,982 788,038 — — — — — — — — — — — — — — 10 934,800 — — 934,810 $1,722,848 2,905,173 (q) 2,014,715 (166,497) (2,664,977) (y) (2,664,977) $ (2,757,704) $ 66,397 $ 246,141 442,034 — 22,034 776,606 23,060 217,434 — — 1,017,100 2,044,877 — 1,453 2,029,978 (206,163) — — — — (240,196) 1,585,072 $ 4,647,049 $ 69 Reorganization Adjustments (a) Reflects the net cash payments that occurred on the Effective Date as follows: Funding of professional fee escrow account Payment of non-retained professional fees Payment of Predecessor RCF, including accrued interest Proceeds from Exit Facilities Receipt of cash from the issuance of First Lien Notes through primary Private Placement and primary Rights Offering Change in cash and cash equivalents (b) Reflects the change in restricted cash for the following activities: Funding of professional fee escrow account Payment of key employee incentive plan holdback escrow account Payment of pre-petition trade claims Change in restricted cash April 23, 2021 (35,003) (14,087) (479,627) 200,000 75,000 (253,717) April 23, 2021 35,003 (1,697) (1,133) 32,173 $ $ $ $ (c) Reflects the changes in prepaid expenses and other current assets for the following activities: Reduction of prepaid expense for success fees Reclassification of debt issuance costs to other assets and long-term debt Reclassification of payment-in-kind upfront fee related to the Exit RCF to other assets Write-off of Predecessor directors and officers tail insurance policy Change in prepaid expenses and other current assets April 23, 2021 (1,095) (10,328) (3,478) (583) (15,484) $ $ (d) As a result of an amendment that became effective on the Effective Date, the BOP leases were recharacterized from operating leases to finance leases pursuant to FASB ASC Topic 842, Leases (or ASC 842). The impact of the recharacterization resulted in the reclassification of the ROU asset of $116.2 million from “Other assets” into “Drilling and other property and equipment.” The value of the BOP ROU assets and the corresponding finance lease liabilities after the amendment were increased by an adjustment of $66.8 million in accordance with the modification guidance of ASC 842. (e) Reflects the changes in other assets for the following activities: Reclassification of BOP lease asset to drilling and other property and equipment Reclassification of payment-in-kind upfront fee related to the Exit RCF from prepaid expenses and other current assets Record debt issuance costs related to the Exit RCF Write-off of Predecessor directors and officers tail insurance policy Change in other assets April 23, 2021 (116,242) 3,478 6,659 (6,349) (112,454) $ $ (f) Reflects the $1.0 million reduction in accounts payable for the payment of pre-petition trade claims and associated post-petition interest related to general unsecured claims. 70 (g) Reflects the changes in accrued liabilities for the following activities: Record accrued liability related to success fees Record accrued liability related to a bonus accrual under the amended BOP services agreement Reclassification of BOP short-term lease liability into a finance lease Payment of non-retained professional fees Payment of key employee incentive plan holdback awards Payment of accrued interest related to Predecessor RCF Reclassification of payment-in-kind upfront fee into the Exit RCF Reclassification of backstop commitment premium to payment-in-kind First Lien Notes Change in accrued liabilities (h) Reflects the changes in short-term debt for the following activities: Record Predecessor RCF cash paydown of principal Reflects payment in full of the borrowings outstanding under the Predecessor RCF on the Effective Date Change in short-term debt April 23, 2021 10,699 831 (17,225) (8,762) (1,697) (37,593) (3,478) (9,900) (67,125) April 23, 2021 (242,034) (200,000) (442,034) $ $ $ $ (i) Reflects the reclassification of the current BOP operating lease liability to a finance lease of $17.2 million, net of the modification pursuant to ASC 842 of the current BOP finance lease liability of $2.1 million. (j) Reflects the adjustment to deferred taxes of $3.9 million due to the step plan adjustments recorded as a result of the Plan. (k) Reflects the reclassification of the non-current BOP operating lease liability to a finance lease of $(90.1) million. (l) Reflects the reclassification of the non-current BOP operating lease liability to a finance lease of $90.1 million and the modification of the non-current BOP finance lease liability of $68.8 million pursuant to ASC 842. (m) Reflects the changes in long-term debt for the following activities: Borrowings drawn under the Exit Facilities Record payment-in-kind upfront fee related to the Exit RCF Issuance of First Lien Notes for cash Record 1% premium associated with First Lien Notes Record backstop commitment premium to payment-in-kind First Lien Notes Record debt issuance costs related to Exit Term Loans and First Lien Notes Change in long-term debt (n) Liabilities subject to compromise were settled as follows in accordance with the Plan: Senior Notes Claims Total settled liabilities subject to compromise Issuance of New Diamond Common Shares to holders of Senior Notes Claims Issuance of New Diamond Common Shares to participants of the Rights Offering and Private Placements Record 1% premium associated with First Lien Notes Pre-tax gain on settlement of liabilities subject to compromise April 23, 2021 200,000 3,478 75,000 749 10,424 (3,669) 285,982 April 23, 2021 2,044,877 2,044,877 (639,965) (274,271) (749) 1,129,892 $ $ $ $ 71 (o) Reflects the cancellation of the Predecessor’s common stock, treasury stock and related components of the Predecessor’s additional paid-in capital. (p) The following reconciles reorganization adjustments made to the Successor’s common stock and Successor’s additional paid-in capital: Fair value of New Diamond Common Shares issued to holders of Senior Notes Claims Fair value of Emergence Warrants issued to Predecessor equity holders Total change in Successor common stock and additional paid-in capital Less: Par value of Successor common stock Successor additional paid-in capital (q) Reflects the cumulative net impact of the effects on accumulated deficit as follows: Success fee recognized on the Effective Date Pre-tax gain on settlement of liabilities subject to compromise Backstop commitment expense to record difference between accrued termination fee and issuance of payment-in-kind First Lien Notes upon emergence Write-off of Predecessor directors and officers tail insurance policy Other emergence effects Expense related to bonus accrual under BOP services agreement Cancellation of Predecessor common stock, additional paid-in capital and treasury stock Issuance of Emergence Warrants to Predecessor equity holders Change in deferred tax as a result of step plan adjustments Change in accumulated deficit Fresh Start Adjustments April 23, 2021 914,236 20,574 934,810 (10) 934,800 April 23, 2021 (17,120) 1,129,892 (524) (6,932) (137) (831) 1,825,268 (20,574) (3,869) 2,905,173 $ $ $ $ (r) Reclassification of a net debit in the “Deferred tax liability” account to “Deferred tax asset” after the adjustment pursuant to ASC 740 based on the impact of the tax effects of the reorganization and the fair value ascribed to the enterprise upon emergence, with a portion classified to “Accounts receivable” based on the expected amount to be received from the amended tax return. (s) Reflects the write-off of current deferred contract assets of $(27.3) million, as there was no future benefit to be recognized by the Successor, and the fair value adjustment of $(7.2) million to rig spare parts and supplies. (t) Reflects the fair value adjustment to “Drilling and other property and equipment” and the elimination of accumulated depreciation of $(2,712.1) million. In addition, the adjustment reflects the fair value adjustment of $(8.4) million to the BOP finance lease assets by setting the ROU assets equal to the ROU liabilities less the prepaid amounts. Refer to the valuation procedures set forth above with respect to valuing the rigs and related equipment. (u) Reflects the fair value adjustments to “Other assets” for the following: Write-off of long-term contract assets Fair value adjustment to set asset equal to right-of-use liability for other operating leases Fair value adjustment to other operating leases to reflect the IBR on the Effective Date Change in other assets April 23, 2021 (10,029) (1,998) 1,745 (10,282) $ $ (v) Reflects the write-off of current deferred contract liabilities of $(56.4) million as there is no future obligation to be performed by the Successor and the fair value adjustment of $0.4 million to current other lease liabilities because of the impact of applying the IBR at the Effective Date at emergence. (w) Reflects the adjustment to deferred taxes of $(34.4) million pursuant to ASC 740 based on the impact of the tax effects of the reorganization, inclusive of the Successor company’s tax basis, and the fair value ascribed to the enterprise upon emergence. 72 (x) Reflects the write-off of non-current deferred contract liabilities of $(11.1) million as there was no future obligation to be performed by the Successor and the fair value adjustment of $1.3 million to non-current other lease liabilities. (y) Reflects the cumulative effect of the fresh start accounting adjustments discussed above. 4. Revenue from Contracts with Customers The activities that primarily drive the revenue earned from our contract drilling services include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services. Consideration for activities that are not distinct within the context of our contracts and do not correspond to a distinct time increment within the contract term are allocated across the single performance obligation and recognized ratably over the initial term of the contract (which is the period we estimate to be benefited from the corresponding activities and generally ranges from two to 60 months). Consideration for activities that correspond to a distinct time increment within the contract term is recognized in the period when the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. See below for further discussion regarding the allocation of the transaction price to the remaining performance obligations. The amount estimated for variable consideration may be constrained (reduced) and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, management considers whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are reassessed each reporting period as required. Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour. Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset. In some contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on our past experience and knowledge of market conditions. 73 Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, the customer may compensate us for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract. Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements or upgrades to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). The activities related to these capital modifications are not considered to be distinct within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract. Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed. Revenues Related to Managed Rigs. In May 2021, we entered into an arrangement with an offshore drilling company whereby we provide management and marketing services (or the MMSA) for certain of its rigs. Per the MMSA, for stacked rigs we earn a daily service fee and are entitled to reimbursement of direct costs incurred in accordance with the agreement. The daily service fee revenue is recognized in line with the contractual rate billed for the services provided and is reported in “Contract Drilling Revenue” in our Consolidated Statements of Operations. We record the revenue relating to reimbursed expenses at the gross amount incurred and billed to the rig owner, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations. The managed rigs West Auriga and West Vela commenced operations in the U.S. Gulf of Mexico in March 2022 and October 2022, respectively. Upon commencement of drilling operations, the MMSA for both rigs was suspended and replaced by a charter agreement for the duration of the drilling contracts. We entered into the drilling contract directly with the customer and recognize revenue under the terms of the contract. We report such revenue as “Contract drilling” in our Consolidated Statements of Operations. In addition, we have determined that the charter arrangement is an operating lease, and the related charter fee has been reported as lease expense within "Contract drilling, excluding depreciation" in our Consolidated Statements of Operations. Contract Balances Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances consist primarily of demobilization revenue that we expect to receive and is recognized ratably throughout the contract term, but invoiced upon completion of the demobilization activities. Once the demobilization revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract assets may also include amounts recognized in advance of amounts invoiced due to the blending of rates when a contract has operating dayrates that increase over the initial contract term. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract. Additionally, amounts received in relation to the MMSA in advance of services rendered are deferred as contract liabilities and recognized in reimbursable revenue as reimbursable costs are incurred on behalf of the rig owner. Contract liabilities may also include amounts invoiced in advance of amounts recognized due to the blending of rates when a contract has operating dayrates that decrease over the initial contract term. 74 Contract balances are netted at a contract level, such that deferred revenue for mobilization, contract preparation and capital modifications (contract liabilities) is netted with any accrued demobilization revenue (contract asset) for each applicable contract. The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers (in thousands): Trade receivables Current contract assets (1) Noncurrent contract assets (1) Current contract liabilities (deferred revenue) (1) Noncurrent contract liabilities (deferred revenue) (1) $ December 31, 2022 2021 155,956 $ 141 — (11,513) (487) 130,021 1,835 — (38,506) (9,787) (1) Contract assets and contract liabilities may reflect balances that have been netted together on a contract basis. Net current contract asset and liability balances are included in “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, and net noncurrent contract asset and liability balances are included in “Other assets” and “Other liabilities,” respectively, in our Consolidated Balance Sheets as of December 31, 2022 and 2021. Significant changes in net contract assets and the contract liabilities balances during the period are as follows (in thousands): Successor December 31, 2022 April 24, 2021 through December 31, 2021 Contract assets, beginning of period Contract liabilities, beginning of period Net balance at beginning of period $ 1,835 $ (48,293) (46,458) Decrease due to amortization of revenue that was included in the beginning contract liabilities balance 26,909 418 — 418 — Predecessor January 1, 2021 through December 31, April 23, 2021 $ 2,870 $ (56,927) (54,057) 2020 6,314 (48,104) (41,790) 15,341 35,231 Increase due to cash received, excluding amounts recognized as revenue during the period Increase due to revenue recognized during the period but contingent on future performance Decrease due to transfer to receivables during the period Write-off of deferred revenue due to application of fresh start accounting Adjustments (1) Net balance at end of period Contract assets at end of period Contract liabilities at end of period (2,445) (48,293) (22,553) (44,081) 6,619 1,417 1,442 4,748 (8,312) — (700) (7,466) — 11,828 (11,859) $ 141 $ (12,000) — — (46,458) 1,835 (48,293) $ $ $ $ 60,945 — 418 $ 418 $ — — (699) (54,057) 2,870 (56,927) (1) Upon commencement of drilling operations, the MMSA for the managed rigs was suspended and replaced by a charter agreement for the duration of the contract. As a result, we reclassified $11.1 million previously recorded as a contract liability to “Contract advances,” which was reported as a component of “Accrued liabilities” in our Consolidated Balance Sheet at December 31, 2022. Deferred Contract Costs Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related 75 drilling contract. Such deferred contract costs in the amount of $14.4 million and $0.3 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheet at December 31, 2022. Deferred contract costs in the amount of $7.3 million and $5.8 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheet at December 31, 2021. The amount of amortization of such costs was $7.3 million, $1.0 million, $6.3 million and $22.8 million for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and for the year ended December 31, 2020, respectively. Excluding the effects of fresh start accounting, there was no impairment loss in relation to capitalized costs. Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement. Transaction Price Allocated to Remaining Performance Obligations The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations as of December 31, 2022 (in thousands): Mobilization and contract preparation revenue Capital modification revenue Demobilization and other deferred revenue Total $ $ 2023 For the Years Ending December 31, 2024 Total 6,352 5,138 (164) 11,326 $ $ 225 287 — 512 $ $ 6,577 5,425 (164) 11,838 The revenue included above consists of expected fixed mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations, as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. Revenue expected to be recognized in the future related to the blending of rates when a contract has operating dayrates that decrease over the initial contract term is also included. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2022. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have applied the disclosure practical expedient in Topic 606 and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue. 76 5. Asset Impairments 2021 Impairment. During the first quarter of 2021, we identified indicators that the carrying amounts of certain of our assets may not be recoverable and evaluated three of our drilling rigs with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the carrying value of one of these rigs, for which we had concerns regarding future opportunities, was impaired. We recorded asset impairments aggregating $197.0 million for the Predecessor period from January 1, 2021 through April 23, 2021. Pursuant to fresh start accounting, our long-lived assets, including our drilling rigs, were valued at their estimated fair value on the Effective Date based on assumptions and market factors that we believed to be accurate at that time. On the Effective Date, the remaining economic useful life of each individual rig was validated or revised, if so indicated. Subsequently, at the end of 2021, we reviewed the marketability, age and physical condition of certain of our rigs in conjunction with other factors specific to the geographic markets in which our rigs are capable of operating and determined that, based on circumstances that arose in the fourth quarter of 2021, which we believed to be other than temporary, the economic useful lives of certain of the rigs in our fleet were materially different than that determined at the Effective Date. At December 31, 2021, we identified three semisubmersible rigs for which we believed a change in the economic useful life was appropriate. In connection with this reassessment, we evaluated each rig for recoverability and determined that the carrying values of two of these rigs were impaired. We recorded an aggregate impairment loss of $132.4 million in the Successor period from April 24, 2021 through December 31, 2021 to write down the carrying value of these rigs to their estimated fair values. In addition, we reviewed one other rig with an indicator of impairment and determined that no impairment had occurred at December 31, 2021. We collectively refer to rigs impaired during the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 as the 2021 Impaired Rigs. We estimated the fair values of the 2021 Impaired Rigs using an income approach, whereby the fair value of the rig was estimated based on a calculation of each rig’s future net cash flows. These calculations utilized significant unobservable inputs, including management’s assumptions related to estimated dayrate revenue, rig utilization and, when applicable, estimated capital expenditures, repair and regulatory survey costs, as well as estimated proceeds that may be received on ultimate disposition of the rig. Our fair value estimate was representative of a Level 3 fair value measurement due to the significant level of estimation involved and the lack of transparency as to the inputs used. 2020 Impairments. During the first quarter of 2020, the business climate in which we operate experienced a significant adverse change that resulted in a dramatic decline in oil prices. During the first quarter of 2020, we evaluated five rigs with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the carrying values of four of our drilling rigs were impaired and recorded an aggregate impairment charge of $774.0 million to write down the carrying values of these rigs to their estimated fair values. During the fourth quarter of 2020, we evaluated three drilling rigs with indicators of impairment, including one rig that was previously impaired in the first quarter of 2020. Based on further diminished business opportunities for the previously impaired rig, we reassessed our business plan and, after consideration of several factors, including the costs of relocating and stacking the rig, concluded that the carrying value of this rig was impaired at December 31, 2020. We recognized an additional impairment charge of $68.0 million to further adjust the carrying value of this rig to its fair value. We collectively refer to rigs impaired during the first and fourth quarters of 2020 as the 2020 Impaired Rigs. We estimated the fair values of the 2020 Impaired Rigs using an income approach, as described above. Our fair value estimates were representative of Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used. See Note 1 "General Information — Impairment of Long-Lived Assets" and Note 9 "Financial Instruments and Fair Value Disclosures." 6. Supplemental Financial Information Consolidated Balance Sheet Information Accounts receivable, net of allowance for bad debts, consists of the following (in thousands): Trade receivables Federal income tax receivables Value added tax receivables Related party receivables Other Allowance for credit losses Total December 31, 2022 2021 $ $ 155,956 $ 9,450 6,075 73 6,121 177,675 (5,622) 172,053 $ 130,021 9,278 9,729 66 2,823 151,917 (5,582) 146,335 The allowance for credit losses at December 31, 2022 and 2021 represents our current estimate of credit losses associated with our “Trade receivables” and “Current contract assets.” See Note 9 “Financial Instruments and Fair Value Disclosures” for a discussion of our concentrations of credit risk and allowance for credit losses. Prepaid expenses and other current assets consist of the following (in thousands): Prepaid taxes Deferred contract costs Rig spare parts and supplies Prepaid rig costs Prepaid insurance Deferred survey costs Current contract assets Collateral deposits Other Total Accrued liabilities consist of the following (in thousands): Contract advances Rig operating costs Payroll and benefits Current operating lease liability Deferred revenue Accrued capital project/upgrade costs Shorebase and administrative costs Personal injury and other claims Interest payable Deposit for equipment sale Other Total December 31, 2022 2021 16,922 14,373 5,091 4,001 3,022 838 141 — 4,307 48,695 $ 16,163 7,267 3,716 4,048 3,436 511 1,835 17,480 6,984 61,440 December 31, 2022 2021 52,743 $ 39,288 29,408 13,480 11,513 8,419 4,365 3,738 1,897 1,670 264 166,785 $ — 42,532 29,268 15,998 38,506 2,219 5,776 5,598 2,986 — 853 143,736 $ $ $ Consolidated Statements of Cash Flows Information Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows (in thousands): Successor For the Year Ended December 31, 2022 Successor Period from April 24 through December 31, 2021 Predecessor Period from January 1 through April 23, 2021 For the Year Ended December 31, 2020 Accrued but unpaid capital expenditures at period end $ Accrued but unpaid debt issuance costs and arrangement fees (1) Common stock withheld for payroll tax obligations (2) Cash interest payments Cash paid for reorganization items, net Cash income taxes paid (refunded), net: Foreign U.S. federal State 8,419 $ 2,219 $ 18,617 $ 7,615 — 4,252 27,767 — 13,178 110 — — — 13,671 36,154 1,969 468 — 7,588 — 37,593 37,566 3,460 — (34) — 395 19,843 40,301 11,826 (42,462) 36 (1) Represents unpaid debt issuance costs related to our exit financing that were incurred and capitalized during the Predecessor period from January 1, 2021 through April 23, 2021, which were accrued at April 23, 2021. In total, we incurred and capitalized financing costs of $13.8 million in relation to our exit financing. (2) Represents the cost of 563,727 and 131,698 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of equity awards in the Successor year ended December 31, 2022 and the Predecessor year ended December 31, 2020, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheet at December 31, 2022. In June 2020, we received Trinidad bonds in settlement of a value-added-tax (or VAT) receivable. The bonds were valued at $5.7 million based on third-party quotes received, which approximated the amount of the settled receivable. During the third quarter of 2020, we sold the bonds for proceeds of $5.9 million. 7. Stock-Based Compensation We have an equity incentive compensation plan for our officers, independent contractors, employees and non- employee directors which is designed to encourage stock ownership by such persons. We may grant both time-vesting and performance-vesting awards, which are earned on the achievement of certain performance criteria. The following types of awards may be granted under our incentive plan: • • • • • Stock options (including incentive stock options and nonqualified stock options); Stock appreciation rights (or SARs); Restricted stock; Restricted stock units (or RSUs); Performance shares or units; and • Other stock-based awards (including dividend equivalents). Successor Plan Pursuant to the terms of the Plan, the Diamond Offshore Drilling, Inc. 2021 Long-Term Stock Incentive Plan (or the Equity Incentive Plan) was adopted and approved on the Effective Date. The Equity Incentive Plan provides for the grant of stock options, SARs, restricted stock, RSUs, performance awards, and other stock-based awards or any combination thereof to eligible participants. Vesting conditions and other terms and conditions of awards under the Equity Incentive Plan are determined by our Board of Directors (or Board) or the compensation committee of our Board, subject to the terms of the Equity Incentive Plan. RSUs and restricted stock awards may be issued with performance-vesting or time-vesting features and, except for restricted stock awards issued to our Chief Executive Officer, they are not participating securities. The aggregate number of shares of Common Stock initially available for issuance pursuant to awards under the Equity Incentive Plan was 11,111,111. Total compensation cost recognized for all awards under the Equity Incentive Plan for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 to December 31, 2021 was $20.2 million and $10.8 million, respectively. Tax benefits recognized for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 to December 31, 2021 were $2.9 million and $2.0 million, respectively. As of December 31, 2022, there was $11.7 million of total unrecognized compensation cost related to non-vested awards under the Equity Incentive Plan, which we expect to recognize over a weighted average period of one and one-half years. Time-Vesting Awards RSUs. RSUs are contractual rights to receive shares of our Common Stock in the future if the applicable vesting conditions are met. During the Successor period, we granted an aggregate 347,797 time-vesting RSU awards to our non-employee members of the Board (or Board RSUs). The Board RSUs vest and become non-forfeitable with respect to 30% of the RSUs on the first anniversary of the grant date and 70% of the RSUs on the second anniversary of the grant date, subject to the recipient’s continuous service through the applicable vesting date. The vested Board RSUs will be issued at the earliest of (i) the fifth anniversary of the grant date, (ii) a separation from service, or (iii) a change in control. The recipients may elect, with respect to up to 40% of the vested and non-forfeitable Board RSUs, to receive cash equal to the fair market value of those RSUs instead of shares. Accordingly, 40% of the Board RSUs are considered liability-classified awards, which are remeasured each period. The remaining 60% of the Board RSUs are equity-classified awards, for which the fair value was estimated based on the fair market value of our Common Stock on the date of grant. Effective July 1, 2021, the Board approved a new key employee retention and incentive plan covering executive officers and certain non-executive key employees. During the year ended December 31, 2022, and the Successor period between April 24, 2021 and December 31, 2021 we granted 535,516 and 1,916,043 time-vesting RSUs, respectively. The RSUs will vest annually over a period of three years from the grant date. Restricted Stock. Pursuant to the terms of the Equity Incentive Plan, we granted 222,222 shares of time-vesting restricted stock awards to our Chief Executive Officer. Two-thirds of the time-vesting awards were issued and have vested, and the remaining one-third will vest in May 2023, subject to his continuous service or employment. Holders of restricted stock have all privileges of a stockholder of the Company with respect to the restricted stock, including without limitation the right to vote any shares underlying such restricted stock and to receive dividends or other distributions in respect thereof. The fair value of time-vesting RSUs and restricted stock awards granted under the Equity Incentive Plan was estimated based on the fair market value of our Common Stock on the date of grant. A summary of time-vesting RSU and restricted stock award activity under the Successor Equity Incentive Plan as of December 31, 2022 and changes during the year ended December 31, 2022 is as follows: Nonvested awards at January 1, 2022 Granted Vested Forfeited Nonvested awards at December 31, 2022 Weighted -Average Grant Date Fair Value Per Share 8.75 6.68 8.75 8.44 8.20 Number of Awards 2,178,690 $ 545,651 $ (616,835) $ (162,368) $ 1,945,138 $ The weighted average grant-date fair value of restricted stock awards granted during the year ended December 31, 2022 and the Successor period from April 24, 2021 to December 31, 2021 was $6.68 and $8.75, respectively. The total fair value of the restricted stock awards that vested during the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 was $3.9 million and $0.6 million, respectively. Performance-Vesting Awards RSUs. During the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021, we granted 709,148 and 1,733,404 performance-vesting RSU awards, respectively. The performance-vesting RSUs granted during the Successor year ended December 31, 2022 will vest at the end of a three-year period upon the achievement of certain market conditions and continuous employment of the award holder. The fair value of these shares was estimated using a Monte Carlo simulation. The performance-vesting RSUs granted during the Successor period from April 24, 2021 to December 31, 2021 vest annually over a three-year cycle and are distributed based on performance metrics and continuous employment. The fair value of these shares was estimated based on the fair market value of our Common Stock on the date of grant. A summary of performance-vesting RSU activity under the Equity Incentive Plan as of December 31, 2022 and changes during the year ended December 31, 2022 is as follows: Nonvested awards at January 1, 2022 Granted Vested Forfeited Nonvested awards at December 31, 2022 Weighted -Average Grant Date Fair Value Per Share 8.75 5.71 8.75 8.04 7.42 Number of Awards 1,440,641 $ 709,148 $ (444,474) $ (184,018) $ 1,521,297 $ The weighted average grant-date fair value of performance awards granted during the year ended December 31, 2022 and the Successor period from April 24, 2021 to December 31, 2021 was $5.71 and $8.75, respectively. The total fair value of performance awards vested during year ended December 31, 2022 was $3.2 million. Restricted Stock. In May 2021, we granted 777,777 shares of performance-vesting restricted stock to our Chief Executive Officer pursuant to the terms of the Equity Incentive Plan. These awards vest upon achievement of both a market and performance condition, and any awards not vested as of May 8, 2027 will be forfeited. Vesting is contingent upon certain conditions (as defined in the award agreement under the Equity Incentive Plan). As of December 31, 2022, a significant portion of the vesting conditions had been satisfied, resulting in the vesting of 747,407 shares of restricted stock during 2022. We recognized the total estimated grant date fair value of these awards of $5.4 million as compensation expense during the Successor year ended December 31, 2022. The weighted-average grant-date fair value of these performance-vesting restricted stock awards was $6.89 million. The total fair value of the awards that vested during the year ended December 31, 2022 was $6.2 million. The performance-vesting restricted stock awards granted during the year ended December 31, 2022 and the performance-vesting restricted stock awards granted to our Chief Executive Officer during the Successor period from April 24, 2021 through December 31, 2021 were valued using a Monte Carlo simulation assuming a Geometric Brownian Motion in a risk-neutral framework and using the following assumptions: Expected life of awards (in years) Expected volatility Risk-free interest rate Awards granted 2022 2021 3 75.00% 2.71% 3 70.00% 0.29% A summary of performance-vesting restricted stock activity under the Successor Equity Incentive Plan as of December 31, 2022 and changes during the year ended December 31, 2022 is as follows: Nonvested awards at January 1, 2022 Vested Nonvested awards at December 31, 2022 Predecessor Plan Weighted -Average Grant Date Fair Value Per Share 6.89 6.89 6.89 Number of Awards 777,777 $ (747,407) $ 30,370 $ Under the Predecessor's Equity Incentive Compensation Plan (or the Predecessor Equity Plan), we had a maximum of 7,500,000 shares of our common stock initially available for the grant or settlement of awards, subject to adjustment for certain business transactions and changes in capital structure. On May 27, 2020, the Bankruptcy Court approved a new key employee retention plan and a new non-executive incentive plan covering certain non- executive key employees. On June 23, 2020, the Bankruptcy Court approved a key employee incentive plan covering certain additional key employees, including our executive officers. Upon the participating employee’s acceptance of an award under the new compensation plans, all outstanding unvested incentive awards previously granted to the employee under our Predecessor Equity Plan, consisting of time-vesting RSUs and/or SARs, were canceled. Any remaining outstanding awards under the Predecessor Equity Plan were automatically canceled on the Effective Date. Total compensation cost and tax benefit recognized for all awards under the Predecessor Equity Plan for the Predecessor year ended December 31, 2020 were $5.6 million and $0.2 million, respectively. Due to the cancellation of the awards under the Predecessor Equity Plan described above, no additional compensation cost is recognizable related to the Predecessor plan. 8. Loss Per Share We present basic and diluted loss per share on our Consolidated Statements of Operations. Basic loss per share excludes dilution and is computed by dividing net loss by the weighted-average number of shares of common stock outstanding for the period. We experienced net losses for the Successor periods for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020. We have excluded shares of common stock issuable upon exercise of outstanding stock appreciation rights and vesting of outstanding restricted stock units from the calculation of weighted-average shares because their inclusion would be antidilutive. 9. Financial Instruments and Fair Value Disclosures Concentrations of Credit Risk and Allowance for Credit Losses Our credit risk corresponds primarily to trade receivables. Since the market for our services is the offshore oil and gas industry, our customer base consists primarily of major and independent oil and gas companies, as well as government-owned oil companies. At December 31, 2022, we believe that we had potentially significant concentrations of credit risk due to the number of rigs we currently had contracted and our limited number of customers, as some of our customers have contracted for multiple rigs. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain, we perform a credit review on that customer, including a review of its credit ratings and financial statements. Based on that credit review, we may require that the customer have a bank issue a letter of credit on its behalf, prepay for the services in advance or provide other credit enhancements. We had not required any other credit enhancements by our customers or required any to pay for services in advance at December 31, 2022. Prior to the adoption of FASB ASU No. 2016-13 Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (or ASU 2016-13), we historically recorded a provision for bad debts on a case-by-case basis when facts and circumstances indicated that a customer receivable may not be collectible. In establishing these reserves, we considered historical and other factors that predicted collectability of such customer receivables, including write-offs, recoveries and the monitoring of credit quality. The amounts reserved for uncollectible accounts in previous periods have not been significant, individually or in comparison to our total revenues. ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates. We adopted ASU 2016-13 and its related amendments (or collectively, CECL) effective January 1, 2020 by recognizing a cumulative-effect adjustment to our Consolidated Financial Statements, which was not material and has been reported in “Contract drilling, excluding depreciation” expense in our Consolidated Statements of Operations, rather than opening retained earnings as prescribed in ASU 2016-13. We have applied CECL prospectively. Pursuant to ASU 2016-13, we reviewed our historical credit loss experience over a look-back period of ten years, which we deem to be representative of both up-turns and down-cycles in the offshore drilling industry. Based on this review, we developed a credit loss factor using a weighted-average ratio of our actual credit losses to revenues during the look-back period. We also considered current and future anticipated economic conditions in determining our credit loss factor, including crude oil prices and liquidity of credit markets. In applying the requirements of CECL, we determined that it would be appropriate to segregate our trade receivables into three credit loss risk pools based on customer credit ratings, each of which represents a tier of increasing credit risk. We calculated a credit loss factor based on historical loss rate information and applied a multiple of our credit loss factor to each of these risk pools, considering the impact of current and future economic information and the level of risk associated with these pools, to calculate our current estimate of credit losses. Trade receivables that are fully covered by allowances for credit losses are excluded from these risk pools for purposes of calculating our current estimate of credit losses. At December 31, 2022, $6.1 million in trade receivables were considered past due by 30 days or more, of which $5.5 million have been fully reserved. The remaining $0.6 million were less than a year past due and considered collectible. For purposes of calculating our current estimate of credit losses at December 31, 2022 and 2021, all trade receivables, except for those fully-reserved, were deemed to be in a single risk pool based on their credit ratings at each respective period. Our total allowance for credit losses was $5.6 million at both December 31, 2022 and 2021, including $0.2 million and $0.1 million at December 31, 2022 and 2021, respectively, related to our current estimate of credit losses under CECL. See Note 6 “Supplemental Financial Information — Consolidated Balance Sheet Information.” Fair Values Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value: Level 1 Quoted prices for identical instruments in active markets. Level 2 Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 3 Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We recorded impairment charges related to certain of our drilling rigs, which were measured at fair value on a nonrecurring basis during the Successor period from April 24, 2021 through December 31 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020. The aggregate losses for the periods have been presented as “Impairment of assets” in our Consolidated Statements of Operations for the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020. See Note 5 “Asset Impairments.” Assets and liabilities measured at fair value are summarized below (in thousands). Successor December 31, 2022 Fair Value Measurements Using Level 1 Level 2 Level 3 Assets and Liabilities at Fair Value Total Losses for Year Ended (1) Recurring fair value measurements Liability-classified Director restricted stock units $ (818) $ (818) $ (230) Successor December 31, 2021 Fair Value Measurements Using Level 1 Level 2 Level 3 Assets and Liabilities at Fair Value Total Losses for Period from April 24, 2021 through December 31, 2021 (2) Predecessor Total Losses for Period from January 1, 2021 to April 23, 2021 (3) Recurring fair value measurements Liability-classified Director restricted stock units Nonrecurring fair value measurements Impaired assets (4) $ $ (528) $ — $ — $ (528) $ (528) $ — — $ — $ 77,900 $ 77,900 $ 132,449 $ 197,027 Predecessor December 31, 2020 Fair Value Measurements Using Nonrecurring fair value measurements Level 1 Level 2 Level 3 Assets at Fair Value Total Losses for Year Ended (5) Impaired assets (6) $ — $ — $ 1,000 $ 1,000 $842,016 (1) Represents an increase in stock compensation expense due to the “marking-to-market” of liability-classified restricted stock units granted to our non-employee directors. (2) Represents an impairment charge recognized during the Successor period from April 24, 2021 through December 31, 2021 related to two semisubmersible rigs that were written down to their estimated fair value. (3) Represents an impairment charge recognized during the Predecessor period from January 1, 2021 through April 23, 2021 related to one semisubmersible rig, which was written down to its estimated fair value. (4) Represents the total book value as of December 31, 2021 of two semisubmersible rigs, which were written down to estimated fair value during the Successor period from April 24, 2021 through December 31, 2021. (5) Represents impairment losses of $774.0 million and $68.0 million recognized during the first and fourth quarters of the Predecessor year ended December 31, 2020, respectively, related to four semisubmersible rigs which were written down to their estimated fair value. (6) Represents the total book value as of December 31, 2020 of one semisubmersible rig, which was written down to its estimated fair value during the fourth quarter of the Predecessor year ended December 31, 2020. We believe that the carrying amounts of our other financial assets and liabilities (excluding our Exit Term Loans, First Lien Notes and the Predecessor Senior Notes), which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the following assumptions: • • • Cash and cash equivalents and restricted cash — The carrying amounts approximate fair value because of the short maturity of these instruments. Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of the instruments. Exit RCF Borrowings - The carrying amount approximates fair value since the variable interest rates are tied to current market rates and the applicable margins represent market rates. Our debt is not measured at fair value on a recurring basis; however, under the GAAP fair value hierarchy, our Exit Term Loans, First Lien Notes and the Predecessor Senior Notes would be considered Level 2 liabilities. The fair value of these instruments was derived using a third-party pricing service at December 31, 2022 and 2021. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and for the Senior Notes, comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our Exit Term Loans, First Lien Notes and the Predecessor Senior Notes Senior Notes (see Note 11 "Prepetition Revolving Credit Facility, Senior Notes and Exit Debt") are shown below (in millions). Exit Term Loans First Lien Notes December 31, 2022 2021 Fair Value Carrying Value Fair Value Carrying Value $ 91.1 $ 78.3 100.0 $ 85.3 100.0 $ 86.2 100.0 86.1 We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange. 10. Drilling and Other Property and Equipment Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows (in thousands): Drilling rigs and equipment Finance lease right of use asset Land and buildings Office equipment and other Cost Less: accumulated depreciation Drilling and other property and equipment, net December 31, 2022 1,126,793 $ 174,571 10,001 2,515 1,313,880 (171,972) 1,141,908 $ 2021 1,057,739 174,571 9,823 2,264 1,244,397 (68,502) 1,175,895 $ $ 11. Prepetition Revolving Credit Facility, Senior Notes and Exit Debt Prepetition Revolving Credit Facility In 2018, Diamond Offshore Drilling, Inc., or DODI, as the U.S. borrower, and our subsidiary DFAC, as the foreign borrower, entered into a syndicated, 5-year Revolving Credit Agreement, under which we had borrowings outstanding in the aggregate amount of $436.0 million on the Petition Date. Subsequently, in January 2021, a $6.0 million financial letter of credit previously issued under the RCF was drawn on by the beneficiary and converted to an adjusted base rate loan. As a result, total outstanding borrowings under the RCF prior to the Effective Date were $442.0 million. On April 26, 2020, as a result of commencement of the Chapter 11 Cases, we ceased accruing interest on our borrowings under the RCF. Additionally, we wrote off $3.9 million in deferred arrangement fees associated with the RCF during the Predecessor year ended December 31, 2020, which was reported as “Reorganization items, net” in our Consolidated Statements of Operations. As a result of the signing of the PSA in January 2021, we no longer considered the outstanding borrowings and accrued pre-petition interest on the RCF to be debt subject to compromise, as such claims, including accrued interest since the Petition Date, were to be settled in full upon emergence from bankruptcy. In addition, due to provisions in the PSA and other orders of the Bankruptcy Court, we resumed recognizing interest on our outstanding borrowings under the RCF in the first quarter of 2021, including unpaid post-petition interest of $21.3 million not previously recognized for the Predecessor year ended December 31, 2020. See Note 2 “Chapter 11 Proceedings – Chapter 11 Cases.” On the Effective Date, the RCF claims were settled as follows: • • Approximately $279.6 million paid in cash; and Rollover of prepetition RCF into new debt of $200.0 million on a dollar-for-dollar basis. See “—Exit Debt — Exit Revolving Credit Agreement” and “—Exit Debt — Exit Term Loan Credit Agreement.” Senior Notes Upon commencement of the Chapter 11 Cases, we ceased accruing interest on the Senior Notes, which had an aggregate principal balance of $2.0 billion on the Petition Date. As a result, we did not record $76.7 million of contractual interest expense related to our Senior Notes for the Predecessor year ended December 31, 2020. In addition, we wrote off $23.7 million in unamortized discount and debt issuance costs associated with the Senior Notes during the Predecessor year ended December 31, 2020, which have been reported as "Reorganization items, net" in our Consolidated Statements of Operations. On the Effective Date, New Diamond Common Shares were transferred pro rata to the holders of the Senior Notes in exchange for the cancellation of the aggregate $2.0 billion principal balance of the Senior Notes. See Note 2 “Chapter 11 Proceedings – Chapter 11 Cases.” As a result of the cancellation of the Senior Notes and associated accrued interest of $44.9 million, we recognized a pre-tax gain on extinguishment of debt of approximately $1.1 billion which was reported in “Reorganization items, net” in the Predecessor’s Consolidated Statement of Operations for the period January 1, 2021 through April 23, 2021. Exit Debt At December 31, 2022 and 2021, the carrying value of the Successor long-term debt (or Exit Debt), net of unamortized discount, premium and debt issuance costs, was comprised as follows (in thousands): Borrowings under Exit RCF Exit Term Loans First Lien Notes Total Exit Debt, net December 31, 2022 2021 $ $ 177,478 99,190 83,976 360,644 $ $ 83,478 99,034 83,729 266,241 The borrower under the Exit RCF and the Exit Term Loan Credit Agreement (or, collectively, the Credit Facilities) is DFAC (or the Borrower) and the co-issuers of the First Lien Notes are DFAC and DFLLC (or, together, the Issuers). The Credit Facilities and the First Lien Notes are unconditionally guaranteed, on a joint and several basis, by the Borrower and certain of its direct and indirect subsidiaries (or, collectively with the Borrower, the Credit Parties and each, a Credit Party) and secured by senior priority liens on substantially all of the assets of, and the equity interests in, each Credit Party, including all rigs owned by the Company as of the Effective Date or acquired thereafter and certain assets related thereto, in each case, subject to certain exceptions and limitations described in the Credit Facilities and the First Lien Notes Indenture. As of December 31, 2022, the aggregate annual maturity of the Successor Exit Debt, excluding net unamortized premium and debt issuance costs of $0.7 million and $2.8 million, respectively, was as follows (in thousands): Year Ending December 31, 2023 2024 2025 2026 2027 Thereafter Total maturities of long-term debt Exit Revolving Credit Agreement Aggregate Principal Amount — — — 177,478 185,321 — 362,799 $ $ On the Effective Date, the Company entered into the Exit RCF, which provides for a $400.0 million senior secured revolving credit facility and also originally provided for certain Exit RCF lenders (or the LC Lenders) to issue up to $100.0 million of letters of credit. On August 31, 2022, one of the LC Lenders in our Exit RCF notified us that it would exercise its right to resign as an LC Lender with regard to future letters of credit effective September 30, 2022. The resigning LC Lender had previously committed to issue up to $25.0 million in letters of credit under the Exit RCF. On February 21, 2023, we received notification from a second LC Lender that it would exercise its right to resign as an LC Lender effective March 23, 2023. This second LC Lender had previously committed to issue up to $25.0 million in letters of credit under the Exit RCF. Each resigning LC Lender continues to have all of the rights and obligations of an LC Lender under the Exit RCF with respect to letters of credit issued by it prior to its resignation but, after the effective date of its resignation, is not required to issue additional letters of credit or extend, renew or increase the outstanding letters of credit. As a result of the resignations discussed above, the aggregate amount of the commitments of the LC Lenders to issue letters of credit under the Exit RCF was reduced from $100.0 million to $75.0 million effective September 30, 2022, and will be reduced to $50.0 million effective March 23, 2023. Our total capacity for borrowings under the Exit RCF was not impacted by the resignation of the LC Lenders and remains at $400 million. The Exit RCF is scheduled to mature on April 22, 2026. Borrowings under the Exit RCF may be used to finance capital expenditures, pay fees, commissions and expenses in connection with the loan transactions and consummation of the Plan, and for working capital and other general corporate purposes. Availability of borrowings under the Exit RCF is subject to the satisfaction of certain conditions, including restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, (i) the aggregate amount of Available Cash (as defined in the Exit Revolving Credit Agreement) would exceed $125.0 million or (ii) the Collateral Coverage Ratio (as defined below) would be less than 2.00 to 1.00 and the aggregate principal amount outstanding under the Exit RCF would exceed $400.0 million and/or the Total Collateral Coverage Ratio (as defined below) would be less than 1.30 to 1.00. On the Effective Date, the Borrower incurred loans under the Exit RCF in an aggregate amount of approximately $103.5 million, of which $100.0 million was deemed incurred in exchange for certain obligations of the Company under its prepetition RCF and approximately $3.5 million was deemed incurred in satisfaction of certain upfront fees payable to the lenders under the prepetition RCF (or PIK Loans). The PIK Loans do not reduce the amount of available commitments under the Exit RCF, and if repaid or prepaid may not be reborrowed. Loans outstanding under the Exit RCF bear interest at a rate per annum equal to the applicable margin plus, at the Borrower’s option, either: (i) the reserve-adjusted London Interbank Offered Rate (or LIBOR Rate), subject to a floor of 1.00%, or (ii) a base rate, subject to a floor of 2.00%, determined as the greatest of (x) the rate per annum publicly announced from time to time by Wells Fargo Bank, National Association, as its prime rate (or the Wells Fargo Prime Rate), (y) the federal funds effective rate plus ½ of 1.00%, and (z) the reserve-adjusted one-month LIBOR Rate plus 1.00%. The applicable margin was initially 4.25% per annum for LIBOR Rate loans and 3.25% per annum for base rate loans. Mandatory prepayments and, under certain circumstances, commitment reductions are required under the Exit RCF in connection with certain specified asset dispositions (subject to reinvestment rights if no event of default exists). Available Cash (as defined in the Exit Revolving Credit Agreement) in excess of $125 million is also required to be applied periodically to prepay loans (without a commitment reduction). The loans under the Exit RCF may be voluntarily prepaid and the commitments thereunder voluntarily terminated or reduced by the Borrower at any time without premium or penalty, other than customary breakage costs. The Borrower is required to pay a quarterly commitment fee to each lender under the Exit Revolving Credit Agreement, which accrues at a rate per annum equal to 0.50% on the average daily unused portion of such lender’s commitments under the Exit RCF. The Borrower is also required to pay customary letter of credit and fronting fees. The Exit Revolving Credit Agreement obligates the Borrower and its restricted subsidiaries to comply with the following financial maintenance covenants: • • as of the last day of each fiscal quarter, the ratio of (a) the Collateral Rig Value (as defined in the Exit Revolving Credit Agreement), to (b) the aggregate outstanding principal amount of all Loans and L/C Obligations (both as defined in the Exit Revolving Credit Agreement) thereunder (or the Collateral Coverage Ratio) is not permitted to be less than 2.00 to 1.00; and as of the last day of each fiscal quarter, the ratio of (a) the Collateral Rig Value to (b) the sum of (1) the aggregate outstanding principal amount of all Loans and L/C Obligations thereunder, plus (2) the aggregate outstanding principal amount of the Exit Term Loans, plus (3) the aggregate outstanding principal amount of the First Lien Notes, plus (4) the aggregate outstanding principal amount of the Last Out Incremental Debt (or the Total Collateral Coverage Ratio) as of the last day of any such fiscal quarter is not permitted to be less than 1.30 to 1.00. The Exit Revolving Credit Agreement contains negative covenants that limit, among other things, the Borrower’s ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness; (ii) create, incur or assume liens; (iii) make investments; (iv) merge or consolidate with or into any other person or undergo certain other fundamental changes; (v) transfer or sell assets; (vi) pay dividends or distributions on capital stock or redeem or repurchase capital stock; (vii) enter into transactions with certain affiliates; (viii) repay, redeem or amend certain indebtedness; (ix) sell stock of its subsidiaries; or (x) enter into certain burdensome agreements. These negative covenants are subject to a number of important limitations and exceptions. Additionally, the Exit Revolving Credit Agreement contains other covenants, representations and warranties and events of default that are customary for a financing of this type. Events of default include, among other things, nonpayment of principal or interest, breach of covenants, breach of representations and warranties, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a security document to create an effective security interest in collateral, bankruptcy and insolvency events, cross-default to other material indebtedness, and a change of control. At December 31, 2022, we were in compliance with all covenants under the Exit Revolving Credit Agreement. We incurred $6.6 million in debt issuance costs and $3.5 million in paid-in-kind upfront fees in connection with the Exit RCF, which have been deferred and are being amortized as incremental interest expense over the term of the Exit RCF on a straight-line basis. Deferred debt issuance costs and upfront fees associated with the Exit RCF are presented as a component of “Other assets” in the Successor's Consolidated Balance Sheet at December 31, 2022 and 2021. At December 31, 2022, we had borrowings outstanding of $177.5 million under the Exit RCF, including $3.5 million in PIK Loans and had utilized $19.4 million for the issuance of letters of credit. The weighted average interest rate on the combined borrowings outstanding under the Exit RCF at December 31, 2022 was 8.63%. At February 24, 2023, we had borrowings of $162.5 million outstanding under the Exit RCF, excluding the PIK Loans, and had utilized $19.4 million of the Exit RCF for the issuance of a letter of credit in replacement of a previously existing letter of credit. As of February 24, 2023, approximately $221.6 million was available for borrowings or the issuance of letters of credit under the Exit RCF, subject to its terms and conditions. Exit Term Loan Credit Agreement The Exit Term Loan Credit Agreement provides for a $100.0 million senior secured term loan credit facility, scheduled to mature on April 22, 2027. On the Effective Date, the Borrower utilized the entire $100.0 million under the Exit Term Loan Credit Facility to refinance a portion of the Predecessor obligations under the prepetition RCF. The Exit Term Loans outstanding under the Exit Term Loan Credit Facility bear interest at a rate per annum equal to the applicable margin plus, at the Borrower’s option, either: (i) the reserve-adjusted LIBOR Rate, subject to a floor of 1.00% (or LIBOR Rate Term Loans), or (ii) a base rate (or Base Rate Term Loans), subject to a floor of 2.00%, determined as the greatest of (x) the Wells Fargo Prime Rate, (y) the federal funds effective rate plus ½ of 1.00%, and (z) the reserve-adjusted one-month LIBOR Rate plus 1.00%. The margin applicable to LIBOR Rate Term Loans is, at the Borrower’s option: (i) 6.00%, paid in cash; (ii) 4.00% paid in cash plus an additional 4.00% paid in kind; or (iii) 10.00% paid in kind. The margin applicable to Base Rate Term Loans is, at the Borrower’s option: (i) 5.00%, paid in cash; (ii) 3.50% paid in cash plus an additional 3.50% paid in kind; or (iii) 9.00% paid in kind. The Exit Term Loans may be voluntarily prepaid, and the commitments thereunder voluntarily terminated or reduced, by the Borrower at any time without premium or penalty, other than customary breakage costs. Interest on LIBOR Rate Term Loans is payable one, two, three, six, or, if agreed by all lenders, twelve months after such LIBOR Rate Term Loan is disbursed as, converted to or continued as a LIBOR Rate Term Loan, as selected by the Borrower. Interest on Base Rate Term Loans is payable quarterly. The Exit Term Loan Credit Agreement contains negative covenants that limit, among other things, the Borrower’s ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness; (ii) create, incur or assume liens; (iii) make investments; (iv) merge or consolidate with or into any other person or undergo certain other fundamental changes; (v) transfer or sell assets; (vi) pay dividends or distributions on capital stock or redeem or repurchase capital stock; (vii) enter into transactions with certain affiliates; (viii) repay, redeem or amend certain indebtedness; (ix) sell stock of its subsidiaries; or (x) enter into certain burdensome agreements. These negative covenants are subject to a number of important limitations and exceptions. Additionally, the Exit Term Loan Credit Agreement contains other covenants, representations and warranties and events of default that are customary for a financing of this type. Events of default include, among other things, nonpayment of principal or interest, breach of covenants, breach of representations and warranties, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a security document to create an effective security interest in collateral, bankruptcy and insolvency events, any material default under certain material contracts and agreements, cross-default to other material indebtedness, and a change of control. At December 31, 2022, we were in compliance with all covenants under the Exit Term Loan Credit Agreement. The Exit Term Loans were valued at par for fresh start accounting purposes and are presented net of debt issuance costs of $0.8 million, which are being amortized as interest expense over the stated maturity of the loans using the effective interest method. At December 31, 2022, we had Exit Term Loans outstanding of $100.0 million, which accrue interest at 10.384% per annum, assuming a one-month LIBOR and cash interest payment option, and had an effective interest rate of 10.627% per annum. First Lien Notes Indenture On the Effective Date, we entered into the First Lien Notes Indenture and, pursuant to the Backstop Agreement and in accordance with the Plan, (i) consummated the primary rights offering of the Issuers’ First Lien Notes and associated New Diamond Common Shares at an aggregate subscription price of approximately $46.9 million, (ii) closed the delayed draw rights offering of the First Lien Notes and associated New Diamond Common Shares at an aggregate subscription price of approximately $21.9 million, which was committed to but unfunded as of the Effective Date, (iii) consummated the primary private placement of the Issuers’ First Lien Notes and associated New Diamond Common Shares in an aggregate amount of approximately $28.1 million, (iv) closed the delayed draw private placement of the Issuers’ First Lien Notes and associated New Diamond Common Shares in an aggregate amount of approximately $17.8 million, which was committed to but unfunded as of the Effective Date, and (v) paid as consideration to the participants in the Backstop Agreement a commitment premium in the form of additional First Lien Notes in a principal amount of approximately $10.3 million, equal to 9.00% of the aggregate amount of the committed First Lien Notes. First Lien Notes in the aggregate principal amount of $85.3 million were issued on the Effective Date and will mature on April 22, 2027. Interest on the First Lien Notes accrues, at the Issuers’ option, at a rate of: (i) 9.00% per annum, payable in cash; (ii) 11.00% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be payable by issuing additional First Lien Notes (or PIK Notes); or (iii) 13.00% per annum, with the entirety of such interest to be payable by issuing PIK Notes. The Issuers shall pay interest semi-annually in arrears on April 30 and October 31 of each year, commencing October 31, 2021. In addition, the Issuers shall pay a commitment premium of 3% per annum on the aggregate principal amount of undrawn delayed draw First Lien Notes pursuant to the terms of the First Lien Notes Indenture. The First Lien Notes Indenture provides for the early redemption of the First Lien Notes by the Issuers as follows: • • • • before October 23, 2021, all of the First Lien Notes were redeemable at 101% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (none of which were redeemed); on or after October 23, 2021 and prior to April 22, 2023, the First Lien Notes may be redeemed, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount plus the Applicable Premium (as defined in the First Lien Notes Indenture) as of, and accrued and unpaid interest, if any, to, but excluding, the applicable redemption date (none of which were redeemed as of December 31, 2022); on or after April 22, 2023, the First Lien Notes may be redeemed, in whole or in part, at any time and from time to time at fixed redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to, but excluding, the applicable redemption date; and upon a Change of Control (as defined in the First Lien Notes Indenture), the Issuers must offer to purchase all remaining outstanding First Lien Notes at a redemption price equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the applicable redemption date, within 30 days of such Change of Control. The First Lien Notes Indenture contains covenants that limit, among other things, the ability of the Company and certain of its subsidiaries to: (i) incur, assume or guarantee additional indebtedness; (ii) pay dividends or distributions on capital stock or redeem or repurchase capital stock; (iii) make investments; (iv) repay or redeem junior debt; (v) sell stock of its subsidiaries; (vi) transfer or sell assets; (vii) enter into sale and leaseback transactions; (viii) create, incur or assume liens; or (ix) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions. The First Lien Notes Indenture also provides for certain customary events of default, including, among other things, nonpayment of principal or interest, breach of covenants, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a security document to create an effective security interest in collateral, bankruptcy and insolvency events, and cross acceleration, which would permit the principal, premium, if any, interest and other monetary obligations on all the then outstanding First Lien Notes to be declared due and payable immediately. At December 31, 2022, we were in compliance with all covenants under the First Lien Notes Indenture. The First Lien Notes were valued at a 101% of par value for fresh start accounting purposes and are presented net of debt issuance costs of $2.0 million, which are being amortized as interest expense over the stated maturity of the notes using the effective interest method. At December 31, 2022, we had First Lien Notes outstanding aggregating $85.3 million, which accrue interest at 9.0% per annum, assuming a cash interest payment option, and had an effective interest rate of 9.7% per annum. 12. Commitments and Contingencies Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be estimated, we record a liability at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims. Non-Income Tax and Related Claims. We have received assessments related to, or otherwise have exposure to, non-income tax items such as sales-and-use tax, value-added tax, ad valorem tax, custom duties, and other similar taxes in various taxing jurisdictions. We have determined that we have a probable loss for certain of these taxes and the related penalties and interest and, accordingly, have recorded a $12.4 million and $13.7 million liability at December 31, 2022 and 2021, respectively. We intend to defend these matters vigorously; however, the ultimate outcome of these assessments and exposures could result in additional taxes, interest and penalties for which the fully assessed amounts would have a material adverse effect on our financial condition, results of operations or cash flows. Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by one of our customers in Brazil, Petróleo Brasileiro S.A. (or Petrobras), that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. In the opinion of our management, no such pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. Personal Injury Claims. Under our current insurance policies, we self-insure $1.0 million to $5.0 million per occurrence, depending on jurisdiction, with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability in the U.S. Gulf of Mexico. Depending on the nature, severity and frequency of claims that might arise during a policy year, if the aggregate level of claims exceed certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence. For personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico, we self-insure $10.0 million for the first occurrence and, if the aggregate level of claims exceed certain thresholds, we self-insure up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2022, our estimated liability for personal injury claims was $18.3 million, of which $3.7 million and $14.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2021, our estimated liability for personal injury claims was $13.5 million, of which $5.4 million and $8.1 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as: • • • • • the severity of personal injuries claimed; significant changes in the volume of personal injury claims; the unpredictability of legal jurisdictions where the claims will ultimately be litigated; inconsistent court decisions; and the risks and lack of predictability inherent in personal injury litigation. Purchase Obligations. At December 31, 2022, we had no purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business. Services Agreement. In February 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly named Baker Hughes, a GE company) (or Baker Hughes) to provide services with respect to certain blowout preventer and related well control equipment (or Well Control Equipment) on our drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. Future commitments under the contractual services agreements are estimated to be approximately $23.3 million per year or an estimated $112.5 million in the aggregate over the remaining term of the agreements. In addition, we lease Well Control Equipment for our drillships under ten-year finance leases. See Note 13 “Leases and Lease Commitments.” Letters of Credit and Other. We were contingently liable as of December 31, 2022 in connection with approximately $19.4 million in certain tax, supersedeas and customs bonds that have been issued on our behalf. The letter of credit collateralizing these bonds was issued under the Exit RCF and cannot require collateral except in events of default. 13. Leases and Lease Commitments Our leasing activities primarily consist of operating leases for our corporate and shorebase offices, office and information technology equipment, employee housing, vehicles, onshore storage yards and certain rig equipment and tools. We also lease Well Control Equipment under finance leases. Our leases have original terms ranging from one month to ten years, some of which include options to extend the lease for up to five years and/or to terminate the lease within one year. We are participants in four sale and leaseback arrangements with a subsidiary of Baker Hughes pursuant to the 2016 sale of Well Control Equipment on our drillships and corresponding agreements to lease back that equipment under ten-year finance leases for approximately $26.0 million per year in the aggregate with renewal options for two successive five-year periods. At inception, these leases were determined to be operating leases, and the excess carrying value of the Well Control Equipment over the aggregate proceeds received from the sale resulted in the recognition of prepaid rent, which was included in the operating lease ROU asset balance within “Other assets” in our Consolidated Balance Sheet. On the Effective Date, the aggregate remaining prepaid rent balance of $8.4 million was written off in connection with fresh start accounting. On March 31, 2021, we signed an amendment to the operating lease agreement for the Well Control Equipment, which became effective on the Effective Date. The general terms of the lease were unchanged, including the stipulated cost per day and available renewal options; however, a ceiling was added to a previously unpriced purchase option at the end of the original 10-year lease term. This amendment was considered a lease modification effective on April 23, 2021, whereby we were required to reassess lease classification and remeasure the corresponding ROU asset and lease liability. Due to the purchase option ceiling provision included in the amendment, we now believe that we are reasonably certain to exercise the purchase option at the end of the original lease term. Therefore, we have changed the lease classification from an operating lease to a finance lease and remeasured the ROU asset and lease liability to include the estimated purchase option price of the Well Control Equipment. In applying ASU 2016-02, we utilize an exemption for short-term leases whereby we do not record leases with terms of one year or less on the balance sheet. We have also made an accounting policy election not to separate lease components from non-lease components for each of our classes of underlying assets, except for subsea equipment, which includes the Well Control Equipment discussed above. At inception, the consideration for the overall Well Control Equipment arrangement was allocated between the lease and service components based on an estimation of stand-alone selling price of each component, which maximized observable inputs. The costs associated with the service portion of the agreement are accounted for separately from the cost attributable to the equipment leases based on that allocation and thus, are not included in our ROU asset or lease liability balances. The non-lease components for each of our other classes of assets generally relate to maintenance, monitoring and security services and are not separated from their respective lease components. See Note 12 “Commitments and Contingencies.” The lease term used for calculating our ROU assets and lease liabilities is determined by considering the noncancelable lease term, as well as any extension options that we are reasonably certain to exercise. The determination to include option periods is generally made by considering the activity in the region or for the rig corresponding to the respective lease, among other contract-based and market-based factors. We have used our incremental borrowing rate to discount future lease payments as the rate implicit in our leases is not readily determinable. To arrive at our incremental borrowing rate prior to filing of the Chapter 11 Cases, we considered our unsecured borrowings and then adjusted those rates to assume full collateralization and to factor in the individual lease term and payment structure. The incremental borrowing rate for leases entered or modified subsequent to the Petition Date was determined primarily based on secured borrowing rates negotiated in relation to our reorganization and the valuations received for our new debt. Amounts recognized in our Consolidated Balance Sheets for both our operating and finance leases are as follows (in thousands): Operating Leases: Other assets Accrued liabilities Other liabilities Finance Leases: Drilling and other property and equipment, net of accumulated depreciation Current finance lease liabilities Noncurrent finance lease liabilities 145,510 (16,965) (131,393) Components of lease expense are as follows (in thousands): December 31, 2022 2021 $ 30,332 $ (13,480) (16,542) 38,834 (15,998) (22,762) 162,717 (15,865) (148,358) Operating lease cost Finance lease cost: Amortization of ROU assets Interest on lease liabilities Short-term lease cost Variable lease cost (1) Total lease cost $ $ Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through 19,479 $ December 31, 2021 11,754 17,207 10,415 242 12,804 60,147 $ 11,854 7,796 199 1,237 32,840 Period from January 1, 2021 through April 23, 2021 Year Ended December 31, 2020 11,799 $ 35,964 — — 101 598 12,498 $ — — 832 1,465 38,261 $ $ (1) Includes charter expenses incurred post-commencement of drilling operations for the managed rigs. Supplemental information related to leases is as follows (in thousands, except weighted-average data): Operating Leases: Operating cash flows used ROU assets obtained in exchange for lease liabilities Weighted-average remaining lease term (1) Weighted-average discount rate (1) Finance Leases: Operating cash flows used Financing cash flows used ROU assets obtained in exchange for lease liabilities Weighted-average remaining lease term (1) Weighted-average discount rate (1) Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through April 23, 2021 Year Ended December 31, 2020 $ $ 19,031 8,662 4.0 years 6.79% 10,415 15,865 — 3.5 years $ $ $ $ 12,005 19,064 4.4 years 6.53% 7,796 9,845 174,571 4.5 years 6.72% 6.72% 10,817 1,076 5.9 years $ 35,057 10,645 5.6 years 6.89% 8.94% — $ — — n/a n/a — — — n/a n/a (1) Amounts represent the weighted average remaining lease term or discount rate as of the end of the respective period presented. Maturities of lease liabilities as of December 31, 2022 are as follows (in thousands): 2023 2024 2025 2026 2027 Thereafter Total lease payments Less: interest Total lease liability Operating Leases Finance Leases $ $ 14,937 $ 4,845 3,686 3,524 3,437 4,258 34,687 (4,665) 30,022 $ 26,280 $ 26,352 26,280 96,430 — — 175,342 $ (26,984) 148,358 Total 41,217 31,197 29,966 99,954 3,437 4,258 210,029 14. Related-Party Transactions Transactions with Loews. We were party to a services agreement with Loews Corporation (or Loews), our former majority shareholder prior to the Effective Date, under which Loews performed certain administrative and technical services on our behalf (or the Services Agreement) and included internal auditing services and advice and assistance with respect to obtaining insurance. On April 24, 2020, our Services Agreement with Loews was terminated by mutual agreement. We have since retained unrelated third parties to assist us with some of these services, including services related to internal audit functions. We were charged $0.3 million by Loews for these support functions related to the Predecessor year ended December 31, 2020. 15. Restructuring and Separation Costs Prepetition Restructuring Charges. We engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to our capital structure, leading to the commencement of the Chapter 11 Cases in the Bankruptcy Court on April 26, 2020. Prior to the Petition Date, we incurred $7.4 million in legal and other professional advisor fees in connection with the consideration of restructuring alternatives, including the preparation for filing of the Chapter 11 Cases and related matters. We have reported these amounts in “Restructuring and separation costs” in our Consolidated Statements of Operations for the year ended December 31, 2020. Professional fees in connection with the Chapter 11 Cases after the Petition Date are reported in “Reorganization items, net” in our Consolidated Statements of Operations for the Predecessor year ended December 31, 2020. See Note 2 "Chapter 11 Proceedings.” Costs Related to Reductions in Force. In April 2020, we initiated a plan to reduce the number of employees in our world-wide organization in an effort to restructure our business operations and lower operating costs. During the Predecessor year ended December 31, 2020, we incurred $10.3 million, primarily for severance and related costs associated with a reduction in personnel in our corporate offices, warehouse facilities and certain of our international shorebase locations. We have reported these amounts in “Restructuring and separation costs” in our Consolidated Statements of Operations for the Predecessor year ended December 31, 2020. 16. Income Taxes In April 2021, we reorganized under Chapter 11 of the U.S. Bankruptcy Code in a transaction treated as a tax free reorganization under section 368(a)(1)(G) of the Internal Revenue Code of 1986, as amended (or the IRC). We realized approximately $1.3 billion of cancellation of indebtedness (or COD) income for U.S. tax purposes in 2021. Under exceptions applying to COD income resulting from a bankruptcy reorganization, we were not required to recognize this COD income currently as taxable income. Instead, our tax attribute carryforwards, including net operating losses, other noncurrent assets and the stock of our foreign corporate subsidiaries, were reduced under the operative tax statute and applicable regulations, affecting the balance of deferred taxes where appropriate. The total reduction of tax attributes under these rules amounted to approximately $1.3 billion, which impacted net operating losses and, without giving rise to deferred tax consequences, reduced the tax basis of foreign subsidiaries’ stock. The tax attribute reduction occurs on the first day of a company's tax year following the tax year in which COD income was realized, or, in our case, January 1, 2022. In the event of a change in ownership, IRC sections 382 and 383 provide an annual limitation with respect to a corporation’s ability to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. Our emergence from the Chapter 11 Cases resulted in a change in ownership for purposes of IRC section 382. The limitation under the IRC is based on the value of the company as of the emergence date. To achieve business and administrative efficiencies, we undertook an internal restructuring in conjunction with emergence from bankruptcy, resulting in realignment of substantially all our assets and operations under a wholly owned foreign subsidiary, DFAC. Consequently, our management has determined that we will permanently reinvest foreign earnings of foreign subsidiaries. Several of our rigs are owned by Swiss branches of entities incorporated in the United Kingdom, or U.K., that have historically been taxed under a special tax regime pursuant to Swiss corporate income tax rules. On September 3, 2019, the Swiss federal government, along with the Canton of Zug, enacted tax legislation, which we refer to as Swiss Tax Reform, effective as of January 1, 2020. Swiss Tax Reform significantly changed Swiss corporate income tax rules by, among other things, abolishing special tax regimes. At the time Swiss Tax Reform was enacted, uncertainty regarding the tax basis of depreciable property under the normal Swiss tax regime led us to record a $187.0 million reserve for uncertain tax positions. The Swiss tax authorities subsequently provided further clarification, and we reversed such reserve for uncertain tax positions during April 2021. In 2021, deferred tax assets and liabilities were established based on the application of the clarifying guidance and offset by an associated increase in valuation allowance. Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, the mix of international tax jurisdictions in which we operate and recognition of valuation allowances for deferred tax assets for which the tax benefits are not likely to be realized. As of December 31, 2022, all of our rigs are owned and operated, directly or indirectly, by DFAC. Our management has determined that we will permanently reinvest foreign earnings. The potential unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate at December 31, 2022. The components of income tax (benefit) expense are as follows (in thousands): Successor Predecessor Year Ended December 31, 2022 Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through April 23, 2021 Year Ended December 31, Federal – current State – current Foreign – current Total current Federal – deferred Foreign – deferred Total deferred Total $ $ 1,267 $ 10 (4,151) (2,874) 4,538 (4,059) 479 (2,395) $ 3,645 — 1,491 5,136 (6,742) 3,260 (3,482) 1,654 $ $ 171 $ — (3,681) (3,510) (30,955) (4,939) (35,894) (39,404) $ 2020 (11,844) (12) 9,898 (1,958) (7,431) (11,797) (19,228) (21,186) The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following (in thousands): Successor Predecessor Period from April 24, 2021 through December 31, 2021 Year Ended December 31, 2022 $ (7,054) $ (98,552) (1,048) (174,642) $ (105,606) $ (175,690) (36,895) $ 9,871 266 — (22,177) $ — — — Period from January 1, 2021 through April 23, 2021 Year Ended December 31, 2020 $ $ $ $ (336,880) 686,202 (939,210) (2,687,595) (2,001,393) $(1,276,090) (420,292) $ (267,979) (7,003) 7,871 (16,778) — (225,563) (6,771) 2,205 3,318 12,639 (23,135) — — 79,600 (45,919) — — 163,236 515,421 — — 136,262 17,331 25,692 (937) (2,395) $ (7,220) 1,951 1,654 $ $ (67,626) 2,191 (39,404) $ 107,148 1,962 (21,186) (Loss) income before income tax expense: U.S. Foreign Expected income tax benefit at federal statutory rate Effect of tax rate changes Reorganization items Post-petition interest expense Disallowed officers' compensation and restricted stock unit awards Interest and penalties reported as income tax expense Effect of foreign operations Valuation allowance Uncertain tax positions, settlements and adjustments relating to prior years Other Income tax (benefit) expense The reorganization items listed above in the reconciliation to the statutory income tax rate are inclusive of the impact of fresh start accounting, bankruptcy-related costs, internal restructuring and the impact of attribute reduction. The impact of most reorganization items is offset by valuation allowance. Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows (in thousands): Deferred tax assets: Net operating loss carryforwards, or NOLs Foreign tax credits Disallowed interest deduction Worker’s compensation and other current accruals Deferred deductions Deferred revenue Operating lease liability Property, plant and equipment Other Total deferred tax assets Valuation allowance Net deferred tax assets Deferred tax liabilities: Right-of-use assets Other Total deferred tax liabilities Net deferred tax asset December 31, 2022 2021 $ 412,152 $ 27,223 69,604 6,273 7,661 33 22,011 129,938 7,234 682,129 (650,193) 31,936 (21,374) (652) (22,026) $ 9,910 $ 226,022 29,243 70,492 5,150 6,869 6,282 33,815 334,757 4,971 717,601 (673,452) 44,149 (33,117) (871) (33,988) 10,161 Net Operating Loss Carryforwards. As of December 31, 2022, we recorded a deferred tax asset of 412.2 million for the benefit of NOL carryforwards, comprised of $59.8 million related to our U.S. losses and $352.4 million related to our international operations. Approximately $139.1 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $273.0 million relates to NOL carryforwards in several of our foreign subsidiaries, as well as in the U.S. Unless utilized, these NOL carryforwards will expire between 2024 and 2037. As a result of our emergence from bankruptcy, we have significant limitations on our ability to utilize certain U.S. deferred tax assets. Foreign Tax Credits. As of December 31, 2022, we recorded a deferred tax asset of $27.2 million for the benefit of foreign tax credits in the U.S. Of this balance, $2.6 million relates to a foreign tax credit carryback, which is expected to generate a cash tax benefit. The remaining credits will expire, unless utilized, between 2023 and 2028. Valuation Allowances. We record a valuation allowance on a portion of our deferred tax assets not expected to be ultimately realized. In determining the need for a valuation allowance, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. As of December 31, 2022, valuation allowances aggregating $650.2 million have been recorded for our net operating losses, foreign tax credits and other deferred tax assets for which the tax benefits are not likely to be realized. We intend to maintain a valuation allowance on our net federal and foreign deferred tax assets until there is sufficient evidence to support the reversal of these allowances. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability achieved. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future U.S. taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as the Company's projections for growth and/or tax planning strategies. Unrecognized Tax Benefits. Our income tax returns are subject to review and examination in the various jurisdictions in which we operate, and we are currently contesting various tax assessments. We accrue for income tax contingencies, or uncertain tax positions, that we believe are not likely to be realized. A rollforward of the beginning and ending amount of unrecognized tax benefits, excluding interest and penalties, is as follows (in thousands): Successor Predecessor For the Period Year Ended April 24, 2021 Balance, beginning of period Additions for current year tax positions Additions for prior year tax positions Reductions for prior year tax positions Reductions related to statute of limitation expirations Balance, end of period $ $ December 31, through December 31, 2021 (26,678) (3,553) (1,424) 1,730 8,777 (21,148) 2022 (21,148) $ (5,993) (504) 4,345 1,760 (21,540) $ For the Period January 31, 2021 through Year Ended December 31, 2020 April 23, 2021 $ (214,626) $ (118,884) — (100,780) (1,559) 2,944 3,653 (26,678) $ (214,626) (1,282) 187,389 1,841 $ The $6.0 million addition for current year uncertain tax positions recorded in the Successor year ended December 31, 2022 was attributable principally to transfer pricing for certain related party transactions. The $4.3 million reduction of uncertain tax positions recorded in the Successor year ended December 31, 2022 principally reflected the strengthening of the U.S. dollar relative to foreign currencies. The $8.8 million reduction of uncertain tax positions recorded in the Successor period from April 24, 2021 through December 31, 2021 was due to expiry of applicable statutes of limitation for tax returns filed between 2014 and 2018 in several jurisdictions. Due to Swiss Tax Reform and the resulting uncertainties regarding treatment of depreciable property, uncertain tax positions were recorded for $86.2 million in 2019 and $100.8 million in 2020. During the Predecessor period from January 1, 2021 through April 23, 2021, further clarification on the treatment of depreciable property resulted in the reversal of the previously recorded amount of $187.0 million. At December 31, 2022, $0.2 million, $1.5 million and $34.7 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheet. At December 31, 2021, $0.3 million, $1.7 million and $47.6 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheet. Of the net unrecognized tax benefits at December 31, 2022, 2021 and 2020, $36.0 million, $48.9 million and $249.0 million, respectively, would affect the effective tax rates if recognized. At December 31, 2022, the amount of accrued interest and penalties related to uncertain tax positions was $3.1 million and $12.6 million, respectively. At December 31, 2021, the amount of accrued interest and penalties related to uncertain tax positions was $3.9 million and $19.7 million, respectively. Interest expense (benefit) recognized during the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 related to uncertain tax positions was $0.9 million, $1.8 million, $0.1 million and $1.9 million, respectively. Penalties recognized during the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 related to uncertain tax positions were $1.0 million, $0.04 million, $(0.4) million and $1.1 million, respectively. We expect the statutes of limitation for the 2014 through 2020 tax years to expire in 2023 for various of our subsidiaries operating in Australia, Malaysia, Romania, Trinidad and Tobago and the U.K. We anticipate that the related unrecognized tax benefit will decrease by $5.0 million at that time. Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. We remain subject to examination by these jurisdictions or are contesting assessments raised upon examinations in respect to the year 2000 and the years 2006 to 2022. We are currently under examination or contesting assessments in Australia, Brazil, Egypt, Equatorial Guinea, Malaysia, Romania and Trinidad and Tobago. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial condition or cash flows. 17. Employee Benefit Plans Defined Contribution Plans We maintain defined contribution retirement plans for our U.S., U.K., and third-country national (or TCN) employees. The plan for our U.S. employees (or the 401k Plan), is designed to qualify under Section 401(k) of the IRC. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. Under the 401k Plan, the employer may elect to match a percentage of each employee's qualifying annual compensation contributed to the 401k Plan on a pre- tax or Roth elective deferral basis. Participants are fully vested in any employer match immediately upon enrollment in the 401k Plan. During the Predecessor year 2020, we matched 100% of the first 5% of each employee’s qualifying annual compensation contributed to the 401k Plan, but ceased matching contributions effective November 2020. Employer matching contributions were resumed in 2022, matching 50% of the first 6% of each employee's qualifying annual compensation contributed to the 401k Plan. For the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31 2020, our provision for contributions was $3.2 million, $0, $0 and $6.2 million, respectively. The defined contribution retirement plan for our U.K. employees provides that we make annual contributions in an amount equal to the employee's contributions generally up to a maximum percentage of the employee's defined compensation per year. Our contribution during 2022, 2021 and 2020 for employees working in the U.K. sector of the North Sea was 4%, 4% and 6%, respectively, of the employee’s defined compensation. Our provision for contributions was $0.9 million, $0.6 million, $0.3 million and $1.8 million for the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, respectively. The defined contribution retirement plan for our TCN employees (or the International Savings Plan) is similar to the 401k Plan. During the Predecessor year 2020, we matched 100% of the first 5% of each employee’s qualifying annual compensation contributed to the International Savings Plan, but ceased matching contributions effective November 2020. Employer matching contributions were resumed in 2022, matching 50% of the first 6% of each employee's qualifying annual compensation contributed to the International Savings Plan. For the Successor periods for the year ended December 31, 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, our provision for contributions was $0.8 million, $0, $0 and $0.2 million, respectively. Deferred Compensation and Supplemental Executive Retirement Plan Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of the applicable percentage of the base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. We ceased matching contributions to the Supplemental Plan effective January 2020. 18. Segments and Geographic Area Analysis We provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations. However, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue-earning process as it relates to the offshore drilling industry over the operating lives of our drilling rigs and other qualitative factors such as (i) the nature of services provided (contract drilling), (ii) similarity in operations (interchangeable rig crews and shared management and marketing, engineering, marine and maintenance support), (iii) similar regulatory environment (depending on customer and/or location) and (iv) similar contractual arrangements with customers. Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At December 31, 2022, our active drilling rigs were located offshore four countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed. The following tables provide information about disaggregated revenue by equipment-type and country (in thousands): United States Senegal Australia United Kingdom Brazil Myanmar Total United States Senegal Australia United Kingdom Brazil Myanmar Total $ $ $ $ Successor Year Ended December 31, 2022 Revenues Related to Reimbursable Expenses Total Contract Drilling Revenues 322,021 $ 154,574 92,939 66,116 80,185 8,909 724,744 $ 75,069 $ 11,929 14,082 8,478 — 6,976 116,534 $ Total 397,090 166,503 107,021 74,594 80,185 15,885 841,278 Successor Period from April 24, 2021 through December 31, 2021 Revenues Related to Reimbursable Expenses Total Contract Drilling Revenues 194,912 $ 48,758 95,601 55,245 42,215 28,597 465,328 $ 55,471 $ 10,110 15,132 3,859 — 6,166 90,738 $ Total 250,383 58,868 110,733 59,104 42,215 34,763 556,066 United States Australia United Kingdom Brazil Myanmar Total United States Australia United Kingdom Brazil Malaysia (1) Total $ $ $ $ Predecessor Period from January 1, 2021 through April 23, 2021 Revenues Related to Reimbursable Expenses Total Contract Drilling Revenues 93,215 $ 17,031 27,967 3,421 11,730 153,364 $ 7,048 $ 4,697 2,300 — 1,970 16,015 $ Total 100,263 21,728 30,267 3,421 13,700 169,379 Predecessor Year Ended December 31, 2020 Revenues Related to Reimbursable Expenses Total Contract Drilling Revenues 321,150 $ 63,876 112,121 155,436 40,170 692,753 $ 13,262 $ 13,271 8,929 (18) 5,490 40,934 $ Total 334,412 77,147 121,050 155,418 45,660 733,687 (1) Revenue earned by the Ocean Monarch during a standby period in Malaysia while awaiting clearance to begin operations in Myanmar waters. The following table presents the locations of our long-lived tangible assets by country as of December 31, 2022, 2021 and 2020. A substantial portion of our assets is comprised of rigs that are mobile and, therefore, asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods and may vary from period to period due to the relocation of rigs. In circumstances where our drilling rigs were in transit at the end of a calendar year, they have been presented in the tables below within the country in which they were expected to operate (in thousands). Drilling and other property and equipment, net: United States International: Senegal United Kingdom Australia Brazil Spain (3) Myanmar Other countries (4) Total Successor December 31, 2022 December 31, 2021 (1) (2) Predecessor December 31, 2020 (2) $ 362,813 $ 559,288 $ 2,162,488 352,655 256,837 91,089 69,596 — — 8,918 779,095 188,694 98,338 106,173 76,383 142,930 2,258 1,831 616,607 $ 1,141,908 $ 1,175,895 — 248,500 722,389 87,543 686,436 207,451 8,002 1,960,321 $ 4,122,809 (1) Balances reflect a fair value adjustment to “Drilling and other property and equipment” and the elimination of accumulated depreciation aggregating $(2,712.1) million. In addition, the adjustment reflects the fair value adjustment of $(8.4) million to the BOP finance lease assets by setting the ROU assets equal to the ROU liabilities less the prepaid amounts. See Note 3 “Fresh Start Accounting.” (2) During the Predecessor period from January 1, 2021 through April 23, 2021 and the Successor period from April 24, 2021 through December, 31, 2021, we recorded aggregate impairment losses of $197.0 million and $132.4 million, respectively, to write down certain of our drilling rigs and related equipment with indicators of impairment to their estimated recoverable amounts. During the Predecessor year 2020, we recorded aggregate impairment losses of $842.0 million to write down certain of our drilling rigs and related equipment with indicators of impairment to their estimated recoverable amounts. (3) The Ocean GreatWhite was relocated to the U.K. in 2022 for reactivation and contract preparation activities. (4) Countries with long-lived assets that individually comprise less than 5% of total drilling and other property and equipment, net of accumulated depreciation. Major Customers Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the Successor periods comprising the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 that contributed more than 10% of our total revenues are as follows: Successor Predecessor Period from April 24, 2021 through December 31, 2021 Period from January 1, 2021 through April 23, 2021 Year Ended December 31, 2022 Year Ended December 31, 2020 33.1% 29.7% 9.5% 4.1% 3.9% — 25.4% 22.4% 7.6% 5.1% 11.5% — 39.8% 0.5% 2.0% 9.2% 21.4% — 20.6% 7.0% 21.2% 10.1% 20.1% 10.7% Customer BP Woodside Petróleo Brasileiro S.A. Shell Occidental Hess Corporation 19. Subsequent Event On February 10, 2023, Apache Beryl I Limited (or Apache) verbally informed us that it intends to exercise its option to terminate its drilling contract for the Ocean Patriot. In accordance with the terms of the drilling contract, the Ocean Patriot will continue to perform services under the contract until at least July 2023. Pursuant to the contract, upon cancellation Apache is obligated to pay an early termination fee of $12.5 million. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Not applicable. Item 9A. Controls and Procedures Disclosure Controls and Procedures We maintain a system of disclosure controls and procedures that are designed to ensure information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure. Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a- 15(e) and 15d-15(e)) as of December 31, 2022. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2022. Internal Control Over Financial Reporting Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error or mistakes, faulty judgments in decision-making and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2022. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on this assessment our management believes that, as of December 31, 2022, our internal control over financial reporting was effective. There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information. Not applicable. Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. Not applicable. Item 10. Directors, Executive Officers and Corporate Governance. PART III Information about our executive officers is reported under the caption “Information About Our Executive Officers” in Item 1 of Part I of this report. Additional information required by this item can be found in our Proxy Statement for our Annual Meeting of Stockholders to be filed with the SEC within 120 days after December 31, 2022 (or 2023 Proxy Statement) and is incorporated herein by reference. Item 11. Executive Compensation. Information required by this item can be found in our 2023 Proxy Statement and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. Information required by this item can be found in our 2023 Proxy Statement and is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions, and Director Independence. Information required by this item can be found in our 2023 Proxy Statement and is incorporated herein by reference. Item 14. Principal Accounting Fees and Services. Information required by this item can be found in our 2023 Proxy Statement and is incorporated herein by reference. PART IV Item 15. Exhibits and Financial Statement Schedules. (a) Index to Financial Statements and Financial Statement Schedules (1) Financial Statements Page Report of Independent Registered Public Accounting Firm (PCAOB ID 00034)............................................ Consolidated Balance Sheets............................................................................................................................ Consolidated Statements of Operations............................................................................................................ Consolidated Statements of Comprehensive Income or Loss........................................................................... Consolidated Statements of Stockholders’ Equity............................................................................................ Consolidated Statements of Cash Flows........................................................................................................... Notes to Consolidated Financial Statements .................................................................................................... 50 53 54 55 56 57 58 (b) Exhibits Exhibit No. Description 2.1 3.1 3.2 4.1 4.2* 10.1 10.2 Second Amended Joint Chapter 11 Plan of Reorganization of Diamond Offshore Drilling, Inc. and Its Debtor Affiliates (incorporated by reference to Exhibit 1 of the Confirmation Order attached as Exhibit 99.1 to our Current Report on Form 8-K filed on April 14, 2021). Third Amended and Restated Certificate of (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on April 29, 2021). Incorporation of Diamond Offshore Drilling, Inc. Third Amended and Restated Bylaws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on February 10, 2023). Indenture, dated as of April 23, 2021, among Diamond Foreign Asset Company, Diamond Finance, LLC, the guarantors party thereto, Wilmington Savings Fund Society, FSB, as trustee, and Wells Fargo Bank, National Association, as collateral agent (including the form of Global Note attached thereto) (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on April 29, 2021). Description of Diamond Offshore Drilling, Inc.'s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934. Senior Secured Term Loan Credit Agreement, dated as of April 23, 2021, by and among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, the lenders party thereto, Wells Fargo Bank, National Association, as administrative agent and collateral agent, Wells Fargo Securities, LLC, Barclays Bank PLC, Citigroup Global Markets Inc., HSBC Securities (USA) Inc., and Truist Bank, as joint lead arrangers and joint bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on April 29, 2021). Senior Secured Revolving Credit Agreement, dated as of April 23, 2021, by and among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, the lenders party thereto, Wells Fargo Bank, National Association, as administrative agent, collateral agent and issuing lender, Wells Fargo Securities, LLC, Barclays Bank PLC, Citigroup Global Markets Inc., HSBC Securities (USA) Inc., and Truist Bank, as joint lead arrangers and joint bookrunners (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on April 29, 2021). 10.3 Warrant Agreement, dated as of April 23, 2021, by and among Diamond Offshore Drilling, Inc., Computershare, Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on April 29, 2021). 10.4 Registration Rights Agreement, dated as of April 23, 2021, by and among Diamond Offshore Drilling, Inc. and the holders party thereto (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed on April 29, 2021). 10.5+ Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006). 10.6+ Form of Indemnification Agreement of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed on April 29, 2021). 10.7+ Diamond Offshore Drilling, Inc. 2021 Long-Term Stock Incentive Plan (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K filed on April 29, 2021). 10.8+ 10.9+ Form of Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.7 to our Current Report on Form 8-K filed on April 29, 2021). Specimen Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on September 3, 2021). 10.10+ Specimen Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on September 3, 2021). 10.11+ Employment Agreement, dated as of May 8, 2021, between Diamond Offshore Drilling, Inc. and Bernie Wolford, Jr. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on May 13, 2021). 10.12+ Restricted Stock Award Agreement, dated as of May 8, 2021, between Diamond Offshore Drilling, Inc. and Bernie Wolford, Jr. with respect to the time-vesting award (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on May 13, 2021). 10.13+ Restricted Stock Award Agreement, dated as of May 8, 2021, between Diamond Offshore Drilling, Inc. and Bernie Wolford, Jr. with respect to the performance-vesting award (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on May 13, 2021). 10.14+ Amendment No. 1, dated as of February 10, 2022, to Restricted Stock Award Agreement, dated as of May 8, 2021, between Diamond Offshore Drilling, Inc. and Bernie Wolford, Jr. with respect to the performance-vesting award (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022). 10.15+ Supplemental Severance Plan (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on September 3, 2021). 10.16+ Specimen Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on May 11, 2022). 10.17+ Specimen Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on May 11, 2022). 10.18** Plan Support Agreement, dated as of January 22, 2021, by and among the Debtors, certain holders of the Company’s former senior notes and certain holders of claims under the Company’s former revolving credit facility (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on January 25, 2021). 10.19+ Form of 2021 Short-Term Incentive Plan Participation Letter (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q/A (Amendment No. 1) for the quarter ended September 30, 2021). 10.20+* Form of 2022 Short-Term Incentive Plan Participation Letter. 10.21+* Form of Time-Vesting Restricted Stock Unit Award Agreement. 10.22+* Form of Executive Performance-Vesting Restricted Stock Unit Award Agreement. 10.23+* Form of Non-Employee Director Restricted Stock Unit Award Agreement. 21.1* List of Subsidiaries of Diamond Offshore Drilling, Inc. 23.1* Consent of Deloitte & Touche LLP. 24.1 Power of Attorney (set forth on the signature page hereof). 31.1* Rule 13a-14(a) Certification of the Chief Executive Officer. 31.2* Rule 13a-14(a) Certification of the Chief Financial Officer. 32.1* Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer. 99.1 Confirmation Order of the United States Bankruptcy Court for the Southern District of Texas, dated April 8, 2021 (incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K filed on April 14, 2021). 101.INS* Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCH* Inline XBRL Taxonomy Extension Schema Document. 101.CAL* Inline XBRL Taxonomy Calculation Linkbase Document. 101.LAB* Inline XBRL Taxonomy Label Linkbase Document. 101.PRE* Inline XBRL Presentation Linkbase Document. 101.DEF* Inline XBRL Definition Linkbase Document. 104* The cover page of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, formatted in Inline XBRL (included with the Exhibit 101 attachments). * Filed or furnished herewith. ** Certain schedules and similar attachments have been omitted. The Company agrees to furnish a supplemental copy of any omitted schedule or attachment to the Securities and Exchange Commission upon request. + Management contracts or compensatory plans or arrangements. Item 16. Form 10-K Summary. None. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 28, 2023. SIGNATURES DIAMOND OFFSHORE DRILLING, INC. By:/s/ DOMINIC A. SAVARINO Dominic A. Savarino Chief Financial Officer POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Dominic A. Savarino and David L. Roland and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re- substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all documents relating to this Annual Report on Form 10-K, including any and all amendments and supplements thereto, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully as to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title /s/ BERNIE WOLFORD, JR. Bernie Wolford, Jr. Director, President and Chief Executive Officer (Principal Executive Officer) /s/ DOMINIC A. SAVARINO Dominic A. Savarino Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) Date February 28, 2023 February 28, 2023 /s/ NEAL P. GOLDMAN Neal P. Goldman /s/ BENJAMIN C. DUSTER, IV Benjamin C. Duster, IV /s/ JOHN H. HOLLOWELL John H. Hollowell /s/ RAJ IYER Raj Iyer /s/ ANE LAUNY Ane Launy /s/ PATRICK CAREY LOWE Patrick Carey Lowe /s/ ADAM C. PEAKES Adam C. Peakes Chairperson of the Board February 28, 2023 Director Director Director Director Director Director February 28, 2023 February 28, 2023 February 28, 2023 February 28, 2023 February 28, 2023 February 28, 2023 EXECUTIVE OFFICERS Bernie G. Wolford Jr. President and Chief Executive Officer Dominic A. Savarino Senior Vice President and Chief Financial Officer David L. Roland Senior Vice President, General Counsel and Secretary CORPORATE HEADQUARTERS 15415 Katy Freeway Houston, TX 77094 281.492.5300 www.diamondoffshore.com Investor Relations Kevin Bordosky Senior Director, Investor Relations 15415 Katy Freeway Houston, TX 77094 281.647.4035 Notice of Annual Meeting The Annual Meeting of Stockholders will be held on Wednesday, May 10, 2023, at 8:30 am (CDT) at the offices of: Diamond Offshore 15415 Katy Freeway Houston, TX 77094 Transfer Agent Computershare PO Box 43078 Providence, RI 02940-3078 877.812.4207 www.computershare.com/investor Stock Exchange Listing New York Stock Exchange Trading Symbol “DO” Independent Auditors Deloitte & Touche LLP BOARD OF DIRECTORS Neal P. Goldman Chairman of the Board; Managing Member of SAGE Capital Investments, LLC Benjamin C. Duster, IV Founder and CEO of Cormorant IV Corporation, LLC John H. Hollowell Former President and Chief Executive Officer of Shell Midstream Partners, L.P. Raj V. Iyer CEO of SpecifX Ane Launy Chief Financial Officer of Heatly AB Patrick Carey Lowe Former Executive Vice President and Chief Operating Officer of Valaris plc Adam C. Peakes Executive Vice President and Chief Financial Officer for the Hornblower Group Bernie G. Wolford, Jr. President and Chief Executive Officer Indide front cover photo: by dstylesimages©️ DIAMOND OFFSHORE Annual Report 2022 15415 Katy Freeway Houston, Texas 77094 281.492.5300 www.diamondoffshore.com