10-K

Age as of
January 31, 2022

Bernie Wolford, Jr.

President, Chief Executive Officer and Director

David L. Roland

Senior Vice President, General Counsel and Secretary

Dominic A. Savarino

Senior Vice President and Chief Financial Officer

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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.

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. ☐

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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: Not applicable because there was no trading market for the registrant's common stock as of June 30, 2021, the last day of the registrant's most recently completed second fiscal quarter.

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Diamond Offshore Drilling, Inc., incorporated in Delaware in 1989, provides contract drilling services to the energy industry around the globe with a fleet of 12 offshore drilling rigs, consisting of four drillships and eight semisubmersible rigs. See “– 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.

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).

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.

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.

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 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 years 2020 and 2019.

See Note 3 “Fresh Start Accounting” to our Consolidated Financial Statements included in Item 8 of this report.

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.

The following table presents additional information regarding our fleet at March 1, 2022:

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.

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 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. 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.

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 of the three rigs, the West Auriga and the West Capricorn, neither of which were operating as of December 31, 2021. We expect to commence management of a third rig, the West Vela, in the first quarter of 2022.

Additionally, we have entered into a charter hire agreement with Aquadrill (or the Charter) for the West Auriga for an upcoming contract in the GOM. While the West Auriga is chartered, the MMSA for the West Auriga will be suspended and will resume upon termination of the Charter. The terms of the Charter are consistent with the MMSA, resulting in the same financial impact to us had the rig 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.

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 from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021, and the years 2020 and 2019, we performed services for seven, eight, ten and twelve different customers, respectively. Our most significant customers during these periods were as follows:

No other customer accounted for 10% or more of our annual total consolidated revenues 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 years 2020 and 2019. 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.

As of January 1, 2022, our contract backlog was an aggregate $1.2 billion attributable to ten customers, compared to $1.2 billion as of January 1, 2021 attributable to nine customers. For the three-year period 2022 to 2024, $0.9 billion (or 80%) of our current contracted backlog is attributable to future operations with three customers, including two customers contracted for three rigs each. 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.

Based on industry data, as of the date of this report, there are approximately 690 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 oversupply of offshore drilling rigs also intensifies price competition. 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.

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.

As of December 31, 2021, we managed a global workforce of approximately 1,900 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, 2021, over 67% of our global workforce had been employed by us for five years or more, with an average tenure of 10 years.

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).

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 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.

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.

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.

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.

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 should not be considered a part of this report or any other filing that we make with the SEC.

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.

The following is a summary of the principal risks that could adversely affect our business, operations and financial results.

For a more complete discussion of the material risks facing our business, see below.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases could adversely affect our business and relationships with vendors, suppliers, service providers, customers, employees and other third parties. Many risks exist as a result of the Chapter 11 Cases and our emergence, including the following:

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our 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, as a consequence of which our assets and liabilities were adjusted to fair values and our accumulated deficit reset to zero. 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.

Following our emergence from bankruptcy, certain stockholders own a significant portion of our common stock and their interests may not always coincide with the interests of other holders of our common stock.

After giving effect to the Plan upon our emergence from bankruptcy, a significant percentage of the outstanding shares of our common stock is held by a relatively small number of investors. As a result of this concentration of our equity ownership, these investors could have significant influence over all matters presented to our stockholders for approval, including, but not limited to, electing directors and approving corporate transactions. These investors may have interests that differ from other stockholders. Circumstances may occur in which the interests of these investors could be in conflict with the interests of other stockholders, and these investors could have substantial influence to cause us to take actions that align with their interests. Should conflicts arise, we can provide no assurance that these investors would act in the best interests of other stockholders or that any conflicts of interest would be resolved in a manner favorable to our other stockholders.

Upon our emergence from bankruptcy, the composition of our Board changed significantly.

Pursuant to the Plan, the composition of our Board changed significantly upon our emergence from bankruptcy. Our Board is now made up of seven directors, with a non-executive Chairperson of the Board, all of whom had not previously served on the Board. These directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that our current Board will pursue, or will pursue in the same manner, our strategic plans in the same manner as our prior Board. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

The impacts of the COVID-19 pandemic and efforts to mitigate the spread of the virus have had a material adverse effect on and could continue to have a material adverse effect on our business, operations and financial results.

The COVID-19 outbreak and its development into a pandemic in March 2020 continue to significantly impact our business and the geographical areas in which we operate. These events continue to result in various actions by governmental authorities in many parts of the world designed to mitigate the spread of COVID-19, such as imposing vaccination requirements, mandatory closures of non-essential business facilities, seeking voluntary closures of other business facilities, declaring border closings, and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions. Moreover, any resurgence in COVID-19 infections could result in the imposition of new governmental lockdowns, quarantine requirements or other restrictions in an effort to slow the spread of the virus. In addition, the risk of infection and health risk associated with COVID-19, including new variants of the virus, and the related death or illness of many individuals across the globe, continue to result in actions by individuals and companies seeking to curtail the spread of COVID-19, such as companies requiring employees to work remotely, suspending non-essential travel for employees and discouraging employee attendance at in-person work-related meetings, as well as individuals voluntarily social distancing and self-quarantining. While many of these measures and restrictions initially implemented during 2020 have since been relaxed or lifted in certain areas around the world in varying degrees, and the development, manufacture and distribution of COVID-19 vaccines during 2021 helped initiate an economic recovery from the pandemic, any resurgence in COVID-19 infections, including the emergence of more contagious and/or vaccine-resistant strains of COVID-19, combined with the effects of low vaccination rates in some populations, could result in the imposition of new governmental lockdowns, quarantine requirements or other restrictions.

The COVID-19 pandemic and the early actions taken by businesses and governments in response to it have significantly slowed global economic activity as a result of, among other things, the dramatic decrease in the number of businesses open for operation and a substantial reduction in the number of people across the world that have been leaving their residence to commute to work or to purchase goods and services. This reduction has also resulted in airlines dramatically reducing flights and led to a sharp reduction in the demand for oil and a precipitous decline in oil prices, although as of the date of this report oil prices have recently risen to the highest level since 2014. In addition, the global economy has been further impacted by the COVID-19 pandemic through the disruption of financial markets and international trade, resulting in increased unemployment levels and significantly impacting global supply chains and travel networks.

These events have had a material adverse effect on and could continue to have 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 have experienced, and expect to continue to experience, increased difficulties, delays and costs in moving our personnel in and out of, and to work in, the various jurisdictions in which we operate. Such difficulties and delays may result in increased costs and a shortage of available experienced rig personnel or rig personnel working unusually long periods before rotating off the rig. We may be unable to fully recover these increased costs from our customers. We may also experience permitting and regulatory delays attributable to the COVID-19 pandemic or reduced staffing at various regulatory agencies. We have also experienced temporary shutdowns due to COVID-19 outbreaks on several of our drilling rigs, which could result in a loss of revenue or contract termination and have substantial adverse consequences for our business and results of operations. Our requirement for the vaccination of all U.S.-based offshore employees and U.S.-based onshore employees who travel to any of our global offshore locations against COVID-19 could lead to the loss of skilled personnel based on vaccination preference.

Additionally, disruptions to or restrictions on the ability of our suppliers, manufacturers and service providers to supply parts, equipment or services in 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, may 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 could result in contract delays or terminations.

In spite of the fact that COVID-19 vaccines are being distributed, the situation surrounding the COVID-19 pandemic remains fluid. Due to delays in the distribution of COVID-19 vaccines and potential resurgences in COVID-19 infections, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist, the extent of the impact they will have on our results of operations, financial condition and liquidity, or the pace or extent of any subsequent recovery. 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 speed of distribution and efficacy of COVID-19 vaccines, 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, all of which continue to be highly uncertain at this time.

Many of the other risks we face are, and will be, exacerbated by the COVID-19 pandemic and any worsening of the business and economic environment as a result of it.

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:

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 other 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. Although an additional 44 rigs were retired since the start of 2020, the market

remains oversupplied as new rig construction and established rigs coming off contract have contributed to the current oversupply, intensifying price competition.

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 or strategy 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. Each of these results in some cases has 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”.

As of the date of this report, three of our drilling rigs have contract backlog that provides for continuous work through various months in 2022. Four of our drilling rigs have contract backlog that provides for continuous work through various times in 2023 and three of our drilling rigs have contract backlog that extends into 2024. Two of our drilling rigs are not currently contracted, one of which is cold stacked.

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.”

locations outside the U.S. accounted for 37% and 22%, respectively, of our total consolidated revenue for the period. During the Predecessor period from January 1, 2021 through April 23, 2021, our two customers in the GOM in the aggregate accounted for 59% of our total consolidated revenue for the period. In addition, the number of customers we have performed services for has declined from 35 in 2014 to eight in 2021. For the three-year period from 2022 to 2024, $0.9 billion (or 80%) of our current contracted backlog is attributable to future operations with three customers, including two customers contracted for three rigs each. The loss of a significant customer could have a material adverse impact on our financial condition, results of operations and cash flows, especially in a 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.

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, 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 for some of our rigs to cover lost cash flow when a rig is unable to work, 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 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 and could have a material adverse effect on our operations, 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 recent industry downturn, global economic conditions 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 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.

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 (i) 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, (ii) diversion of management’s attention from day-to-day operations, (iii) failure to realize anticipated benefits, such as cost savings, revenue enhancements or business synergies, (iv) the potential for substantial transaction expenses and (v) 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.

The debt instruments we entered into on the Effective Date contain various restrictive covenants limiting the discretion of our management in operating 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: (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) enter into sale and leaseback transactions; (vii) pay dividends or distributions on capital stock or redeem or repurchase capital stock; (viii) enter into transactions with certain affiliates; (ix) repay, redeem or amend certain indebtedness; (x) sell stock of its subsidiaries; or (xi) 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 term loan credit agreement and 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.

We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.

The current oversupply of drilling rigs in the offshore drilling market has resulted in numerous rigs being idled and, in some cases, retired and/or scrapped. 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 38 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 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.

Any future 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. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. Moreover, there is increased focus, including by governmental and non-governmental organizations, investors and other stakeholders on these and other sustainability matters. 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. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources, such as wind power and solar energy, or the phase-out of fossil fuel vehicles, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, or adversely affect the demand for hydrocarbons, which may have a material adverse effect on our business, and could have a material adverse effect on our operations by limiting drilling opportunities.

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 recently 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 have 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.

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.

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 early 2021, the newly-elected U.S. President and administration took actions to temporarily suspend the issuance of new oil and gas permits on federal lands and waters in the U.S. for 60 days and signed an executive order directing a pause in new oil and gas leasing on public lands and offshore waters, concurrent with a comprehensive review of the federal oil and gas program. A timeline for the review period has not been specified. We are unable to predict the direct impact of these measures, but such measures could materially adversely impact domestic drilling activities should they be prolonged. In addition, the energy sector could be negatively impacted by additional 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.

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 41%, 55%, 54% and 47% of our total consolidated revenues 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 years ended December 31, 2020 and 2019, respectively, and include, or have included, operations in South America, Australia and Southeast Asia, Europe and Mexico. 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 18% and 11% of our total revenues for the Successor period 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:

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.

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.

Our business, operating results and the value of our common stock could be negatively affected as a result of actions by activist stockholders.

We value constructive input from investors and regularly engage in dialogue with our stockholders regarding strategy and performance. Our Board and management team are committed to acting in the best interests of all of our stockholders. There is no assurance that the actions taken by our Board and management in seeking to maintain constructive engagement with our stockholders will be successful. Activist stockholders who disagree with our operations, including the composition of our Board, our management team or our strategic direction, may seek to effect change through various strategies that range from private engagement to publicity campaigns, proxy contests, efforts to force transactions not supported by our Board and litigation.

If faced with a proxy contest or other stockholder action or request, we may not be able or willing to respond successfully to the contest, action, or request, which could be significantly disruptive to our business. Even if we are successful, our business and operations could be adversely affected by a proxy contest or activist stockholder action or request because:

Any activist stockholder contests, actions or requests, or the mere public presence of activist stockholders among our stockholder base, could cause the market price for our common stock to experience periods of significant volatility based on temporary or speculative market perceptions that do not necessarily reflect our business operations.

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, 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.

As previously disclosed, on July 26, 2021, Avenue Energy Opportunities Fund II AIV, L.P. (or AEOF), a stockholder of the Company, and AEOF’s investment manager, Avenue Capital Management II, L.P. (or, collectively with AEOF, Avenue Capital), filed a complaint against the Company to compel an annual meeting of stockholders pursuant to 8 Del. C. Section 211(c) before the Court of Chancery of the State of Delaware (or the Court, and such proceeding, the Litigation). The Company and Avenue Capital agreed to settle the complaint on August 31, 2021 and, at the request of the parties, on September 1, 2021, the Court ordered the action dismissed with prejudice.

The Company scheduled its annual meeting of stockholders to be held on January 21, 2022 (or the Annual Meeting). On November 18, 2021, Avenue Capital delivered to the Company a purported notice of nominations with respect to the election of Class I directors at the Annual Meeting (or the Nominations Notice). The Company notified Avenue Capital that the Nominations Notice was invalid because neither the Nominations Notice nor Avenue complied with the requirements set forth in the Company’s Bylaws, and therefore the notice could not be accepted. On November 30, 2021, Avenue Capital filed a Motion to Enforce Settlement Agreement in the Litigation (including related motions, the Motion to Enforce), seeking an order compelling the Company to accept the Nominations Notice.

On December 29, 2021, the Company and Avenue Capital entered into an agreement providing for the settlement of any and all disputes among them relating to the Litigation, the Nominations Notice and the Motion to Enforce, without any admissions of guilt, liability, obligation or otherwise (or the Settlement Agreement). Pursuant to the Settlement Agreement, the Nominations Notice and the related demand by Avenue Capital to review certain books and records of the Company under Section 220 of the Delaware General Corporation Law were deemed withdrawn, and the Motion to Enforce and all other pending motions in the Litigation were withdrawn.

Under the terms of the Settlement Agreement, Avenue Capital is subject to customary standstill restrictions during the period from December 29, 2021 until the earlier of (x) the date that is 30 days prior to the deadline for the submission of stockholder nominations of director candidates for the Company’s 2023 annual meeting of stockholders and (y) any public announcement by the Company of an extraordinary transaction (or the Standstill Period). Under the Settlement Agreement, during the Standstill Period, Avenue Capital has agreed to cause its common stock in the Company to be present for quorum purposes at any meeting of the Company’s stockholders at which directors are elected and to vote in favor of the slate of directors nominated by the Company’s Board for election. In addition, the Company has agreed that in the event a vacancy on the Company’s Board arises as a result of certain events occurring prior to the one-year anniversary of the Settlement Agreement, the Company will appoint one director designated by Avenue Capital to fill such vacancy.

Also 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 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Predecessor common stock traded on the New York Stock Exchange (or NYSE) under the symbol “DO” until April 27, 2020, at which time it was removed from trading on the NYSE and subsequently delisted due to our voluntary filing of the Chapter 11 Cases. From April 28, 2020 to April 23, 2021, our Predecessor common stock was quoted on the OTC Pink Open Market under the symbol “DOFSQ.” On the Effective Date, in connection with the effectiveness of, and pursuant to the terms of, the Plan and the Confirmation Order, the Predecessor company's common stock outstanding immediately before the Effective Date was canceled.

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. There is currently no established public trading market for our common stock.

As of March 1, 2022, there were approximately 12 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.

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.

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 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. For a discussion of our financial condition and results of operations for Predecessor years 2020 compared to 2019, 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, 2020 filed with the SEC on February 10, 2021.

We provide contract drilling services to the energy industry around the globe with a fleet of 12 offshore drilling rigs, consisting of four drillships and eight semisubmersible rigs as of the date of this report. The Ocean Valor, which we reported as held for sale at December 31, 2021, was sold in February 2022.

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.

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.

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 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.

On August 3, 2021, we announced that our Board had appointed an independent committee, supported by management, to explore strategic alternatives to maximize shareholder value. These alternatives may include, among other things, continuing as a standalone public company, pursuing asset acquisitions or entering into a business combination with a strategic partner. In connection with the review, Goldman Sachs & Co. LLC has been retained as financial advisor and Milbank LLP has been retained as legal advisor. We have not set a formal timetable for this exploration, nor have we made any decisions related to strategic alternatives at this time. There is no assurance that the process will result in a transaction or any other specific outcome. Although certain transactions have been considered, the Board has not approved a specific action.

Commodity prices have risen since the beginning of 2021, and, in February 2022, the price for Brent crude oil had exceeded the $100-per-barrel level. Current oil and gas prices have been favorably impacted by an increase in demand as the world economies emerge from COVID-19 related shutdowns combined with a growing economy. As a result, demand has risen faster than supply resulting in a rise in commodity prices. In addition, commitments by OPEC+ to maintain its conservative supply program have bolstered the increase in commodity prices, as well as market concerns over oil supply disruptions caused by the conflict in Ukraine. Analysts predict that the market tightness will extend into 2022.

As a result of improved commodity prices, and increased capital spending by our clients, demand for contract drilling services has improved from previous lows. Consequently, the offshore drilling industry has seen contracting activity and dayrates increase in 2021 and continue to do so into 2022, most notably in the deepwater segment of the GOM. However, certain markets, from both a geographical and rig-type perspective, lag in the recovery. Many new contracts remain relatively short in duration but forecasts of total demand, as measured in rig-years, have improved.

With floater utilization of approximately 73% in January 2022, based on industry reports, we remain cautiously optimistic that the offshore drilling market will continue to improve in the foreseeable future, predicated on continued strength in the demand for hydrocarbons. Though demand is expected to improve, rig supply is also expected to increase, assuming there is no further scrapping of rigs. Currently, there are 24 rigs under construction that may be delivered over the coming years; of the rigs under construction only four currently have future drilling contracts. Notwithstanding the potential increase in supply, however, the fundamentals for the offshore drilling market appear to be improving.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2022 through 2024.

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, 2022 (based on information available at that time), October 1, 2021 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2021), and January 1, 2021 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2020) (in millions).

The following table reflects the amounts of our contract drilling backlog by year as of January 1, 2022 (in millions).

The following table reflects the percentage of rig days committed by year as of January 1, 2022. 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).

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 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. The most immediate impact and risks to our business as a result of the COVID-19 pandemic and efforts to mitigate the spread of the virus have been to the safety of our personnel, as well as travel restrictions that have challenged the ability to move personnel, equipment, supplies and service personnel to-and-from our drilling rigs. In some instances, we have asked our rig crews to quarantine in-country before offshore rotations, as well as to remain in country after their offshore rotation, resulting in incremental costs for salaries and other employee-related expenses such as meals and lodging. Our employee travel costs have also increased due to decreased passenger capacity on carriers, requiring additional trips to move personnel. In some cases, we incur freight surcharges to bring equipment and supplies to our rigs. We have also incurred additional costs to deep-clean facilities, for medical personnel and to purchase medical supplies and personal protective equipment.

With respect to protecting our crews and, thus, our rig operations, our COVID-19 protocols are based on the regions in which our rigs operate and the requirements of our customers for which they operate. Such protocols may include some or all of the following:

We incurred incremental costs of approximately $8.9 million, $3.9 million and $12.5 million related to the COVID-19 pandemic 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, respectively. We expect to incur similar types of costs during 2022 but cannot predict the future financial impact of our response to the COVID-19 pandemic nor its duration in this fluid environment. As such, costs may be more than projected, perhaps by a material amount.

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 2022, we expect to spend approximately 165 days of planned downtime, including approximately (i) an aggregate 45 days for mobilization and contract preparation activities for the Ocean BlackHawk’s upcoming contract in Senegal; (ii) 75 days for repairs that are currently underway on the Ocean Endeavor; (iii) 15 days for the mobilization of the Ocean Apex between contracts and (iv) 30 days for the demobilization of the Ocean Onyx after completion of its current contract. In addition, due to events occurring in January 2022, we expect to spend approximately 110 days for the mobilization, repair and special survey of the Ocean Patriot. 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 unable to work, but have not purchased loss-of-hire insurance for our entire fleet.

In addition, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, 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 policies, our deductibles for marine liability coverage are $5.0 million for the first occurrence and vary in amounts ranging between

$5.0 million and, if aggregate claims exceed certain thresholds, 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.

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.

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 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 currently 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 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 capitalized $22.0 million, $59.9 million and $137.4 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:

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 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 further sustained decline in oil and gas prices, cancelations 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.

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 our rigs are capable of operating and determined, based on circumstances that arose in the fourth quarter of 2021, which we believe 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 value of two semisubmersible rigs was 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. During 2020, we recorded an aggregate impairment charge of $842.0 million related to four drilling rigs. We did not incur an impairment loss in 2019. 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.

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).

Contract Drilling Revenue. We earned contract drilling revenue of $465.3 million for the Successor period from April 24, 2021 through December 31, 2021, attributable to 2,250 R-E days and average daily revenue of $206,800. Total utilization for the period was 74%, reflecting 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). The decline in average daily revenue compared to the Predecessor periods reflects lower dayrates earned under new contracts that commenced in 2021 compared to the rigs’ previous contracts, combined with reduced amortization of deferred revenue due to the write-off of previously deferred balances at the Effective Date in connection with fresh start accounting. 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. The decrease in average daily revenue compared to 2020 was primarily related to the Ocean BlackLion starting a new contract in the latter part of 2020 at a lower dayrate than the rig’s previous contract and a decreased dayrate earned by the Ocean BlackHawk as a result of renegotiating its long-term contract in mid-2020 in exchange for additional term.

Contract drilling revenue for the Predecessor year ended December 31, 2020 was $692.8 million attributable to 2,936 R-E days and average daily revenue of $227,000. Total utilization for the period was 59%, reflecting an aggregate 1,098 days of downtime for contracted rigs awaiting and preparing for their upcoming contracts and an aggregate 825 days of downtime attributable to stacked rigs, including the now cold-stacked Ocean Valiant, which completed its most recent contract in early May 2020. Contract drilling revenue for 2020 also included amortization of deferred revenue of $23.2 million and the $26.3 million of revenue recognized pursuant to a gross margin commitment from a customer.

Contract Drilling Expense, Excluding Depreciation. 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 ($158.6 million), rig repairs and maintenance ($66.5 million), shorebase costs and overhead ($36.3 million), equipment rentals ($39.4 million), catering ($11.4 million), freight and transportation ($8.3 million), travel ($7.9 million), insurance ($7.8 million), inspections ($7.3 million), fuel ($5.2 million), amortization of deferred contract preparation and mobilization costs ($1.5 million) and other operating costs in the aggregate ($14.3 million). The reduction in amortized costs compared to the Predecessor periods presented was due to the write off of previously deferred expenses as a result of fresh start accounting. Prior to fresh start accounting, such deferred amounts would have been amortized into expense over the respective contract term; therefore, amortization of such costs in the Successor period relate solely to costs incurred after the Effective Date. Additionally, reduced equipment rental cost compared to the Predecessor periods reflects the impact of a lease modification for our blowout preventer and related well control equipment (or Well Control Equipment) leases on our drillships. Due to a modification of the lease agreements on the Effective Date and change in lease classification, the leases are now considered finance leases, which resulted in the absence of rent expense of approximately $18.2 million for the period.

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).

Contract drilling expense, excluding depreciation, for the Predecessor year ended December 31, 2020 totaled $618.6 million and was comprised primarily of payroll and benefits costs ($255.0 million), rig repairs and maintenance ($103.3 million), equipment rentals ($82.8 million), shorebase costs and overhead ($60.6 million), amortization of deferred contract preparation and mobilization costs ($24.4 million), catering ($18.9 million), inspections ($11.6 million), insurance ($10.9 million), freight and transportation ($10.8 million), fuel ($9.6 million), travel ($9.3 million) and other operating costs in the aggregate ($21.4 million).

Depreciation Expense. Depreciation expense for the Successor period from April 24, 2021 through December 31, 2021 and Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020 was $68.5 million, $92.8 million and $320.1 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.

General and Administrative Expense. 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). Payroll costs for the Successor period included $8.0 million of severance benefits for certain executives who left the Company on or after the Effective Date. Professional and legal costs for the Successor 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 to April 23, 2021, we recognized general and administrative expenses 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).

We incurred general and administrative costs of $56.9 million during the Predecessor year ended December 31, 2020, which consisted of payroll and benefits costs ($40.9 million), professional and legal expenses ($11.7 million) and other administrative costs ($4.3 million).

Impairment of Assets. During the fourth quarter 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, based on circumstances that arose in the fourth quarter of 2021, which we believe to be other than temporary, 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 value of two semisubmersible rigs was 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. During 2020, we recorded an aggregate impairment charge of $842.0 million related to four drilling rigs. See Note 5 “Impairment of Assets” and Note 9 “Financial Instruments and Fair Value Disclosures” to our Consolidated Financial Statements included in Item 8 of this report.

Restructuring and Separation Costs. Prior to the Petition Date in 2020, 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. Also, during the second quarter of 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. As a result of this initiative, we incurred costs of $10.3 million during 2020, 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. See Note 15 “Restructuring and Separation Costs” to our Consolidated Financial Statements in Item 8 of this report.

Gain on Disposition of Assets. During the Predecessor period from January 1, 2021 to 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. During 2020, we recognized an aggregate pre-tax gain of $7.4 million on the disposal of assets, which included pre-tax gains on the sale of our corporate headquarters office building in Houston, Texas ($3.7 million) and the previously impaired Ocean Confidence ($3.5 million).

Interest Expense. During the Successor period from April 24, 2021 through December 31, 2021, we recognized interest expense of $18.4 million related to new debt incurred on or after the Effective Date and incremental interest expense of $7.8 million related to our Well Control Equipment finance leases.

Upon commencing 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 recognizing interest on our outstanding borrowings under the RCF and accrued interest expense of $34.8 million for

the Predecessor period from January 1, 2021, 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.

During 2020, we recognized interest expense relating to the Senior Notes and RCF of $37.0 million and $5.6 million, respectively, for the period prior to our Chapter 11 Petition Date.

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 policy ($6.9 million). These expenses were partially offset by a net gain on settlement of liabilities subject to compromise ($1.1 billion).

During 2020, we recognized $76.9 million in expenses and other net losses directly related to the Chapter 11 Cases, primarily consisting of incremental professional fees incurred ($53.5 million) and the write-off of debt issuance costs associated with our Senior Notes ($27.6 million), partially offset by net gains related to vendor settlements and purchase order cancellations ($4.2 million). See Note 2 “Chapter 11 Proceedings” to our Consolidated Financial Statements in Item 8 of this report.

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 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, an income tax benefit of $39.4 million (2% effective tax rate) for the Predecessor period from January 1, 2021 through April 23, 2021 and an income tax benefit of $21.2 million (1.7% effective tax rate) for the Predecessor year ended December 31, 2020.

During the Successor period from April 24, 2021 through December 31, 2021, the negative effective tax rate reflects changes in the domestic and international jurisdictional mix of our pre-tax income and loss, which are 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.

The effective tax rate of 1.7% for the Predecessor year ended December 31, 2020 includes $9.7 million due to a partial release of a previously recognized valuation allowance and tax rate change as a result of the Coronavirus Aid, Relief and Economic Security Act (or CARES Act). The CARES Act was signed into law by the President of the United States on March 27, 2020 and allowed for a carryback of net operating losses generated in 2018, 2019 and 2020 to each of the five preceding taxable years.

On the Effective Date, in connection with the effectiveness of, and pursuant to the terms of, the Plan and the Confirmation Order:

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.

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:

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 March 1, 2022, we had borrowings of $103.5 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 PIK Loans). We also had utilized $6.1 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 March 1, 2022, approximately $293.9 million was available for borrowings or the issuance of letters of credit under the Exit RCF, subject to its terms and conditions.

For the Successor period April 24, 2021 through December 31, 2021, our operating activities provided cash flow of $18.9 million. 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 finance lease obligations during the period aggregated $42.8 million and $9.8 million, respectively. During the Successor period, we reduced outstanding borrowings under the Exit RCF by a net $20.0 million.

For the Predecessor period 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.

For the Predecessor year 2020, our operating activities provided net cash of $8.4 million. Cash expenditures for contract drilling, shorebase support and general and administrative costs of $826.7 million exceeded cash receipts from contract drilling services of $822.2 million. Operating cash flow for the Predecessor year 2020 also included net tax refunds of $31.2 million, primarily in the U.S. tax jurisdiction, partially offset by cash collateral deposits that we made in support of certain outstanding surety and other bonds and letters of credit ($18.3 million). Other sources of cash during the year were borrowings under the RCF ($436.0 million) and proceeds from the sales of the Ocean Confidence ($4.6 million), our corporate headquarters office building in Houston, Texas ($7.5 million) and Trinidad bonds ($5.9 million). Cash paid for capital expenditures in 2020 was $189.5 million.

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.

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 2022 to be approximately $40.0 million to $50.0 million pursuant to our capital maintenance programs and an additional $15.0 million in survey-related capital expenditures.

Following the commencement of our Chapter 11 Cases, Moody’s Investors Service, Inc. and S&P Global Ratings lowered our credit ratings to default status. They subsequently withdrew our issued credit ratings and outlook and have discontinued their rating coverage of the Company.

The following table sets forth our contractual cash obligations at December 31, 2021 (in thousands).

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 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 for approximately $26.0 million per year in the aggregate. 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, 2021, except for those related to our direct rig operations, which arise during the normal course of business.

We were contingently liable as of December 31, 2021 in the amount of $23.1 million under certain tax, performance, supersedeas, value-added-tax related (or VAT) and customs bonds and letters of credit. Agreements relating to approximately $17.0 million of customs, tax, VAT and supersedeas bonds can require collateral at any time, while the remaining agreements, aggregating $6.1 million, cannot require collateral except in events of default. At December 31, 2021, we had made aggregate collateral deposits of $17.5 million with respect to other bonds and letters of credit. These deposits are recorded in “Other assets” in the Successor Consolidated Balance Sheet at December 31, 2021. The table below provides a list of these obligations in U.S. dollar equivalents by year of expiration (in thousands).

Operations Outside the U.S. Our operations outside the U.S. accounted for approximately 41%, 55%, 54% and 47% of our total consolidated revenues 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 years ended December 31, 2020 and 2019, 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.

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:

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:

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.

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 – Changes in Accounting Principles” to our Consolidated Financial Statements in Item 8 of this report.

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, 2021 and 2020, 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. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

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, 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.

Our Predecessor Senior Notes were issued at fixed rates, and as such, interest expense would not have been impacted by interest rate shifts. However, changes in market interest rates were reflected in the fair value of the debt. The impact of a 100-basis point increase or decrease in interest rates on this fixed rate debt would have resulted in a decrease in market value of $5.1 million or increase in market value of $5.4 million, respectively, as of December 31, 2020.

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.

To the stockholders and the Board of Directors of Diamond Offshore Drilling, Inc.

We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the "Company") as of December 31, 2021 (Successor Company balance sheet) and 2020 (Predecessor Company balance sheet), the related consolidated statements of operations, comprehensive income or loss, stockholders’ equity, and cash flows, for the period of April 24, 2021 to December 31, 2021 (Successor Company operations), the period of January 1, 2021 to April 23, 2021 and for each of the two years in the period ended 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, 2021, and the results of its operations and its cash flows for the period of 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 financial position of the Predecessor Company as of December 31, 2020, and the results of its operations and its cash flows for the period of January 1, 2021 to April 23, 2021, and for each of the two years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

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.

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 Public Company Accounting Oversight Board (United States) (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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impairment of Long-Lived Assets – Refer to Notes 1 and 5 to the financial statements

The evaluation of drilling equipment, specifically drilling rigs, for impairment occurs whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable, such as a change in economic useful life of a rig, cold stacking a drilling rig, the expectation of cold stacking a drilling rig in the near term, a decision to retire or scrap a drilling rig, or excess spending over budget on a newbuild, construction project or major drilling rig upgrade. When the Company determines that the carrying value of a drilling rig may not be recoverable, they prepare an undiscounted probability-weighted cash flow analysis to determine if there is a potential impairment. If the carrying value of a drilling rig is not recoverable, it would be impaired to fair value using a discounted probability-weighted cash flow analysis. These analyses utilize certain assumptions for each drilling rig under evaluation and consider multiple probability-weighted utilization and dayrate scenarios. For the Predecessor Company, drilling and other property and equipment, net of accumulated depreciation was $3.9 billion as of April 23, 2021, and impairment of assets was $197.0 million for the period of January 1, 2021 to April 23, 2021. For the Successor Company, drilling and other property and equipment, net of accumulated depreciation was $1.2 billion as of December 31, 2021, and impairment of assets was $132.4 million for the period of April 24, 2021 to December 31, 2021.

We identified impairment of drilling rigs as a critical audit matter because of the significant judgments made by management to identify indicators of impairment and to develop the dayrate and remaining economic useful life assumptions used in the probability-weighted cash flow analyses to determine if potential impairments exist and measure fair value. This required a high degree of auditor judgment and increased extent of effort, including the involvement of fair value specialists.

Our audit procedures related to (i) the identification of indicators of impairment and (ii) the evaluation of the Company’s undiscounted and discounted probability-weighted cash flow analysis for those drilling rigs with factors that indicated potential impairment included the following, among others:

Emergence from Bankruptcy and Fresh Start Accounting– Refer to Notes 2 and 3 to the financial statements

On April 23, 2021, the Company satisfied all conditions precedent to the Plan of Reorganization and emerged from Chapter 11 bankruptcy. Upon emergence from bankruptcy, the Company met the criteria and were required to adopt fresh start accounting in accordance with ASC 852, Reorganizations. The Company engaged valuation experts to assist with the adoption. Management calculated the fair value of the Successor Company’s assets before considering liabilities (reorganization value of Successor assets)

as $1.7 billion and allocated the value to its individual assets based on their estimated fair values. The Company’s principal assets include its drilling rigs.

The fair value of the Company’s drilling rigs was determined using a combination of the income, cost, and market approaches as outlined within ASC 820, Fair Value Measurement. The income approach involved the compilation of discounted cash flow analyses for each of the Company’s drilling rigs and required management to make significant estimates and assumptions, including, but not limited to, the expected operating dayrates, utilization rates, estimated economic useful lives, and the weighted average cost of capital (or WACC). The Company engaged an independent valuation firm to assist in the compilation of these valuation analyses using generally accepted methods and market data. Changes in these assumptions could have a significant impact on the fair value of the Company’s drilling rigs.

Given the significant judgments made by management, performing audit procedures to evaluate the fair value of the Company’s drilling rigs, including management’s estimates and assumptions related to the dayrate, remaining economic useful life, and WACC used in the discounted cash flow analyses, required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

Our audit procedures related to management’s significant judgments and assumptions related to the application of the fresh start accounting, specifically the fair value of drilling rigs, included the following, among others:

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 $1.6 million as of December 31, 2021 (Successor Company balance sheet), and income tax benefit (expense) was $39.4 million for the period of January 1, 2021 to April 23, 2021 (Predecessor Company operations) and ($1.7 million) for the period of April 24, 2021 to December 31, 2021 (Successor Company operations).

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.

Our audit procedures related to the Company’s application of transfer pricing methodologies, included the following, among others:

The accompanying notes are an integral part of the 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 12 offshore drilling rigs, consisting of four drillships and eight semisubmersible 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.

Change in Accounting Policies

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 period from April 24, 2021 through December 31, 2021, we deferred $0.9 million in survey costs of which $0.5 million and $0.2 million were reported in “Prepaid expenses and other current assets” and "Other assets," respectively, in our Successor Consolidated Balance Sheet at December 31, 2021. We amortized $0.2 million in deferred survey costs as “Contract drilling, excluding depreciation” in the Successor’s Consolidated Statement of Operations for the period from April 24, 2021 through December 31, 2021.

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 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.

Assets Held for Sale

We reported the $1.0 million carrying value of the Ocean Valor, as “Assets 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 $5.5 million. During the Predecessor period from January 1, 2021 through April 23, 2021, we recognized an aggregate pre-tax gain of $4.4 million on the sales of the Ocean America and the Ocean Rover, which were reported as "Assets Held for Sale" in our Predecessor's Consolidated Balance Sheet at December 31, 2020.

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. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. During the Successor period from April 24, 2021 through December 31, 2021, the Predecessor periods from January 1, 2021 through April 23, 2021 and the year ended December 31, 2020, we capitalized $22.0 million, $59.9 million and $137.4 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.

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 Sheet at December 31, 2021 and amortized as interest expense over the respective terms of the credit facility. Deferred costs associated with our long-term debt are presented in the Successor's Consolidated Balance Sheet at

December 31, 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 (expense) benefit” 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 (expense) benefit” 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 period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the two years ended December 31, 2020 and 2019 includes net loss 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).

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

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.

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, as amended by Amendment No. 1 to Form S-1 filed on August 27, 2021, to register 22,892,773 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. As of the date of this report the registration statement is not yet effective.

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:

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a senior secured revolving credit agreement (or the Exit Revolving Credit Agreement), which provides for a $400.0 million senior secured revolving credit facility, with a $100.0 million sublimit for the issuance of letters of credit thereunder (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, 2021.

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 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) cancelled (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.

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		Predecessor
	Period from April 24, 2021		Period from January 1, 2021
	through		through			Year Ended
	December 31, 2021		April 23, 2021			December 31, 2020
Professional fees	$	8,088	$	51,084		$	53,517
Fresh start valuation adjustments		—		2,699,422			—
Net gain on settlement of liabilities subject to compromise		—		(1,129,892	)		—
Accrued backstop commitment premium		—		10,424			—
Write-off of predecessor directors and officers tail insurance policy		—		6,932			—
Write-off of debt issuance costs		—		1,793			27,552
Other		—		—			(4,159	)
Total reorganization items, net	$	8,088	$	1,639,763		$	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. We reported prepetition unsecured and under-secured obligations that we believed to be impacted by the Chapter 11 Cases as “Liabilities subject to compromise” in our Predecessor Consolidated Balance Sheet at December 31, 2020. ASC 852 requires prepetition liabilities that are subject to compromise to be reported at the amounts expected to be allowed by the Bankruptcy Court. The amounts reported as liabilities subject to compromise at December 31, 2020 were preliminary and subject to potential future adjustment depending on Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events. Upon filing the Plan in January 2021, we reclassified all prepetition liabilities out of “Liabilities subject to compromise,” because these claims were to be paid in full and were unimpaired per the Plan, except for our Senior Notes and the corresponding prepetition interest, which were the only claims considered to be impaired and unsecured per the Plan. Thus, at April 23, 2021, “Liabilities subject to compromise” was comprised of the principal balance of our Senior Notes of $2.0 billion and the corresponding accrued interest of $44.9 million.

Liabilities subject to compromise at December 31, 2020 consisted of the following (in thousands):


	Predecessor
	December 31,
	2020
Debt subject to compromise:
Borrowings under the RCF	$	436,000
3.45% Senior Notes due 2023		250,000
7.875% Senior Notes due 2025		500,000
5.70% Senior Notes due 2039		500,000
4.875% Senior Notes due 2043		750,000
Lease liabilities		112,646
Accrued interest		47,636
Accounts payable		16,725
Other accrued liabilities		1,302
Other liabilities		4,496
Total liabilities subject to compromise	$	2,618,805

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.

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):


	April 23,
	2021
Enterprise value	$	1,130,000
Plus: Cash and cash equivalents		79,982
Plus: Deferred tax assets and uncertain tax positions		10,810
Less: Fair value of debt		(285,982	)
Fair value of Successor equity	$	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):


	April 23,
	2021
Enterprise value	$	1,130,000
Plus: Cash and cash equivalents		79,982
Plus: Non-interest bearing current liabilities		225,637
Plus: Non-interest bearing non-current liabilities		276,418
Plus: Deferred tax assets and uncertain tax positions		10,810
Reorganization value of Successor assets	$	1,722,847

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 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.

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.


	April 23, 2021
				Transaction Accounting
	Predecessor			Reorganization Adjustments				Fresh Start Adjustments				Successor
ASSETS
Current assets:
Cash and cash equivalents	$	333,699		$	(253,717	)	(a)	$	—			$	79,982
Restricted cash		3,274			32,173		(b)		—				35,447
Accounts receivable		134,104			—				802		(r)		134,906
Less: allowance for credit losses		(5,555	)		—				—				(5,555	)
Accounts receivable, net		128,549			—				802				129,351
Prepaid expenses and other current assets		108,594			(15,484	)	(c)		(34,455	)	(s)		58,655
Assets held for sale		1,000			—				—				1,000
Total current assets		575,116			(237,028	)			(33,653	)			304,435
Drilling and other property and equipment, net of
accumulated depreciation		3,892,150			182,985		(d)		(2,720,485	)	(t)		1,354,650
Other assets		179,783			(112,454	)	(e)		(10,282	)	(u)		57,047
Deferred tax asset		—			—				6,716		(r)		6,716
Total assets	$	4,647,049		$	(166,497	)		$	(2,757,704	)		$	1,722,848
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	66,397		$	(996	)	(f)	$	—			$	65,401
Accrued liabilities		246,141			(67,125	)	(g)		(55,961	)	(v)		123,055
Short-term debt		442,034			(442,034	)	(h)		—
Finance lease right of use liabilities, current		—			15,148		(i)		—				15,148
Taxes payable		22,034			—				—				22,034
Total current liabilities		776,606			(495,007	)			(55,961	)			225,638
Deferred tax liability		23,060			3,869		(j)		(34,447	)	(w)		—
									7,518		(r)

Other liabilities		217,434			(90,098	)	(k)		(9,837	)	(x)		117,499
Finance lease right of use liabilities, noncurrent		—			158,919		(l)		—				158,919
Long-term debt		—			285,982		(m)		—				285,982
Total liabilities not subject to compromise		1,017,100			(136,335	)			(92,727	)			788,038
Liabilities subject to compromise		2,044,877			(2,044,877	)	(n)		—				—
Stockholders’ equity:
Predecessor preferred stock		—			—				—				—
Predecessor common stock		1,453			(1,453	)	(o)		—				—
Predecessor additional paid-in capital		2,029,978			(2,029,978	)	(o)		—				—
Predecessor treasury stock		(206,163	)		206,163		(o)		—				—
Successor preferred stock		—			—				—				—
Successor common stock		—			10		(p)		—				10
Successor additional paid-in capital		—			934,800		(p)		—				934,800
Successor treasury stock		—			—				—				—
Accumulated deficit		(240,196	)		2,905,173		(q)		(2,664,977	)	(y)		—
Total stockholders’ equity		1,585,072			2,014,715				(2,664,977	)			934,810
Total liabilities and stockholders’ equity	$	4,647,049		$	(166,497	)		$	(2,757,704	)		$	1,722,848

Reorganization Adjustments

(a)

Reflects the net cash payments that occurred on the Effective Date as follows:


	April 23, 2021
Funding of professional fee escrow account	$	(35,003	)
Payment of non-retained professional fees		(14,087	)
Payment of Predecessor RCF, including accrued interest		(479,627	)
Proceeds from Exit Facilities		200,000
Receipt of cash from the issuance of First Lien Notes through primary Private Placement and primary Rights Offering		75,000
Change in cash and cash equivalents	$	(253,717	)

(b)

Reflects the change in restricted cash for the following activities:


	April 23, 2021
Funding of professional fee escrow account	$	35,003
Payment of key employee incentive plan holdback escrow account		(1,697	)
Payment of pre-petition trade claims		(1,133	)
Change in restricted cash	$	32,173

(c)

Reflects the changes in prepaid expenses and other current assets for the following activities:


	April 23, 2021
Reduction of prepaid expense for success fees	$	(1,095	)
Reclassification of debt issuance costs to other assets and long-term debt		(10,328	)
Reclassification of payment-in-kind upfront fee related to the Exit RCF to other assets		(3,478	)
Write-off of Predecessor directors and officers tail insurance policy		(583	)
Change in prepaid expenses and other current assets	$	(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:


	April 23, 2021
Reclassification of BOP lease asset to drilling and other property and equipment	$	(116,242	)
Reclassification of payment-in-kind upfront fee related to the Exit RCF from prepaid expenses and other current assets		3,478
Record debt issuance costs related to the Exit RCF		6,659
Write-off of Predecessor directors and officers tail insurance policy		(6,349	)
Change in other assets	$	(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.

(g)

Reflects the changes in accrued liabilities for the following activities:


	April 23, 2021
Record accrued liability related to success fees	$	10,699
Record accrued liability related to a bonus accrual under the amended BOP services agreement		831
Reclassification of BOP short-term lease liability into a finance lease		(17,225	)
Payment of non-retained professional fees		(8,762	)
Payment of key employee incentive plan holdback awards		(1,697	)
Payment of accrued interest related to Predecessor RCF		(37,593	)
Reclassification of payment-in-kind upfront fee into the Exit RCF		(3,478	)
Reclassification of backstop commitment premium to payment-in-kind First Lien Notes		(9,900	)
Change in accrued liabilities	$	(67,125	)

(h)

Reflects the changes in short-term debt for the following activities:


	April 23, 2021
Record Predecessor RCF cash paydown of principal	$	(242,034	)
Reflects payment in full of the borrowings outstanding under the Predecessor RCF on the Effective Date		(200,000	)
Change in short-term debt	$	(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:


	April 23, 2021
Borrowings drawn under the Exit Facilities	$	200,000
Record payment-in-kind upfront fee related to the Exit RCF		3,478
Issuance of First Lien Notes for cash		75,000
Record 1% premium associated with First Lien Notes		749
Record backstop commitment premium to payment-in-kind First Lien Notes		10,424
Record debt issuance costs related to Exit Term Loans and First Lien Notes		(3,669	)
Change in long-term debt	$	285,982

(n)

Liabilities subject to compromise were settled as follows in accordance with the Plan:


	April 23, 2021
Senior Notes Claims	$	2,044,877
Total settled liabilities subject to compromise		2,044,877

Issuance of New Diamond Common Shares to holders of Senior Notes Claims		(639,965	)
Issuance of New Diamond Common Shares to participants of the Rights Offering and Private Placements		(274,271	)
Record 1% premium associated with First Lien Notes		(749	)
Pre-tax gain on settlement of liabilities subject to compromise	$	1,129,892

(o)

Reflects the cancelation 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:


	April 23, 2021
Fair value of New Diamond Common Shares issued to holders of Senior Notes Claims	$	914,236
Fair value of Emergence Warrants issued to Predecessor equity holders		20,574
Total change in Successor common stock and additional paid-in capital		934,810
Less: Par value of Successor common stock		(10	)
Successor additional paid-in capital	$	934,800

(q)

Reflects the cumulative net impact of the effects on accumulated deficit as follows:


	April 23, 2021
Success fee recognized on the Effective Date	$	(17,120	)
Pre-tax gain on settlement of liabilities subject to compromise		1,129,892
Backstop commitment expense to record difference between accrued termination fee and issuance of payment-in-kind First Lien Notes upon emergence		(524	)
Write-off of Predecessor directors and officers tail insurance policy		(6,932	)
Other emergence effects		(137	)
Expense related to bonus accrual under BOP services agreement		(831	)
Cancellation of Predecessor common stock, additional paid-in capital and treasury stock		1,825,268
Issuance of Emergence Warrants to Predecessor equity holders		(20,574	)
Change in deferred tax as a result of step plan adjustments		(3,869	)
Change in accumulated deficit	$	2,905,173

Fresh Start Adjustments

(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 is 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:


	April 23, 2021
Write-off of long-term contract assets	$	(10,029	)
Fair value adjustment to set asset equal to right-of-use liability for other operating leases		(1,998	)
Fair value adjustment to other operating leases to reflect the IBR on the Effective Date		1,745
Change in other assets	$	(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.

(x)

Reflects the write-off of non-current deferred contract liabilities of $(11.1) million as there is 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.

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 three 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. We currently manage two of these rigs, both of which were considered stacked rigs at December 31, 2021. We expect to commence management of the third rig in 2022.

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.

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):


	Successor			Predecessor
	December 31, 2021			December 31, 2020
Trade receivables	$	130,021		$	115,732
Current contract assets (1)		1,835			2,870
Noncurrent contract assets (1)		—			—
Current contract liabilities (deferred revenue) (1)		(38,506	)		(51,763	)
Noncurrent contract liabilities (deferred revenue) (1)		(9,787	)		(5,164	)

(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, 2021 and 2020.

Significant changes in net contract assets and the contract liabilities balances during the period are as follows (in thousands):


	Successor			Predecessor
	April 24, 2021 through			January 1, 2021 through			December 31,
	December 31, 2021			April 23, 2021			2020
Contract assets, beginning of period	$	418		$	2,870		$	6,314
Contract liabilities, beginning of period		—			(56,927	)		(48,104	)
Net balance at beginning of period		418			(54,057	)		(41,790	)
Decrease due to amortization of revenue that was included in the beginning contract liability balance		—			15,341			35,231
Increase due to cash received, excluding amounts recognized as revenue during the period		(48,293	)		(22,553	)		(44,081	)
Increase due to revenue recognized during the period but contingent on future performance		1,417			1,442			4,748
Decrease due to transfer to receivables during the period		—			(700	)		(7,466	)
Write-off of deferred revenue due to application of fresh start accounting		—			60,945			—
Adjustments		—			—			(699	)
Net balance at end of period	$	(46,458	)	$	418		$	(54,057	)
Contract assets at end of period	$	1,835		$	418		$	2,870
Contract liabilities at end of period		(48,293	)		—			(56,927	)

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 drilling contract. Such 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. Deferred contract costs in the amount of $19.8 million and $2.2 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheet at December 31, 2020. The amount of amortization of such costs was $1.0 million, $6.3 million and $22.8 million for the period from April 24, 2021 through December 31, 2021, the period 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, 2021 (in thousands):



	For the Years Ending December 31,
	2022		2023		2024		Total
Mobilization and contract preparation revenue	$	3,981	$	3,912	$	225	$	8,118
Capital modification revenue		23,407		5,374		287		29,068
Demobilization and other deferred revenue		11,581		—		—		11,581
Total	$	38,969	$	9,286	$	512	$	48,767

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, 2021. 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.

6. Supplemental Financial Information

Consolidated Balance Sheet Information

Accounts receivable, net of allowance for bad debts, consists of the following (in thousands):


	Successor			Predecessor
	December 31,			December 31,
	2021			2020
Trade receivables	$	130,021		$	115,732
Value added tax receivables		9,729			10,781
Federal income tax receivables		9,278			8,420
Related party receivables		66			78
Other		2,823			1,211
		151,917			136,222
Allowance for credit losses		(5,582	)		(5,562	)
Total	$	146,335		$	130,660

The allowance for credit losses at December 31, 2021 and 2020 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):


	Successor		Predecessor
	December 31,		December 31,
	2021		2020
Collateral deposits	$	17,480	$	—
Prepaid taxes		16,163		16,112
Deferred contract costs		7,267		19,808
Prepaid rig costs		4,048		2,317
Rig spare parts and supplies		3,716		12,606
Prepaid insurance		3,436		2,446
Current contract assets		1,835		2,870
Prepaid legal retainers		746		2,408
Other		6,749		3,708
Total	$	61,440	$	62,275

Accrued liabilities consist of the following (in thousands):


	Successor		Predecessor
	December 31,		December 31,
	2021		2020
Rig operating costs	$	42,532	$	21,123
Deferred revenue		38,506		51,763
Payroll and benefits		29,268		30,296
Current operating lease liability		15,998		5,072
Shorebase and administrative costs		5,776		17,275
Personal injury and other claims		5,598		6,495
Interest payable		2,986		—
Accrued capital project/upgrade costs		2,219		7,075
Other		853		1,689
Total	$	143,736	$	140,788

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		Predecessor
	Period from April 24		Period from January 1			For the Year Ended			For the Year Ended
	through December 31,		through April 23,			December 31,			December 31,
	2021		2021			2020			2019
Accrued but unpaid capital expenditures at period end	$	2,219	$	18,617		$	7,615		$	56,603
Accrued but unpaid debt issuance costs and arrangement fees (1)		—		7,588			—			—
Common stock withheld for payroll tax obligations (2)		—		—			395			1,398
Cash interest payments		13,671		37,593			19,843			113,063
Cash paid for reorganization items, net		36,154		37,566			40,301			—
Cash income taxes paid (refunded), net:
Foreign		1,969		3,460			11,826			17,821
U.S. federal		468		—			(42,462	)		1,001
State		—		(34	)		36			(15	)

(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 131,698 and 132,547 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of restricted stock units in 2020 and 2019, respectively. These costs are presented as a deduction from stockholders’ equity in “Predecessor treasury stock” in our Consolidated Balance Sheet at December 31, 2020.

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.

During the Successor period from April 24, 2021 through December 31, 2021, we recognized compensation expense of $10.8 million and a related tax benefit of $2.0 million in relation to the time- and performance-vesting awards described below. As of December 31, 2021, there was $26.9 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 two years. The fair value of time- and performance-vesting RSUs and time-vesting 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.

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 337,662 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. In connection with this plan, we granted 1,916,043 time-vesting RSUs during the second half of 2021 that vest annually over three years.

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. One-third of the time-vesting awards were issued and immediately vested on the May 8, 2021 grant date and the remaining two-thirds vest in equal installments on the first and second anniversaries of the grant date, 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, 2021 and changes for the period from April 24, 2021 through December 31, 2021 is as follows:


	Number of Awards			Weighted -Average Grant Date Fair Value Per Share
Nonvested awards at April 24, 2021		—		$	—
Granted		2,475,927		$	8.75
Vested		(74,074	)	$	8.75
Cancelled		—		$	—
Forfeited		(223,163	)	$	8.75
Nonvested awards at December 31, 2021		2,178,690		$	8.75

The total fair value of the restricted stock awards that vested during the Successor period from April 24, 2021 through December 31, 2021 was $0.6 million.

Performance-Vesting Awards

RSUs. During the Successor period from April 24, 2021 through December 31, 2021, we granted 1,733,404 performance-vesting RSU awards, in connection with the key employee retention and incentive plan approved on July 1, 2021. These RSUs vest annually over three years. The fair value of performance-vesting RSUs granted 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 Successor Equity Incentive Plan as of December 31, 2021 and changes during the period from April 24, 2021 through December 31, 2021 is as follows:


	Number of Awards			Weighted -Average Grant Date Fair Value Per Share
Nonvested awards at April 24, 2021		—		$	—
Granted		1,733,404		$	8.75
Vested		—		$	—
Cancelled		—		$	—
Forfeited		(292,763	)	$	8.75
Nonvested awards at December 31, 2021		1,440,641		$	8.75

Restricted Stock. During the Successor period from April 24, 2021 through December 31, 2021, we granted 777,777 shares of performance-vesting restricted stock awards 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 that have not vested by May 8, 2027 will be forfeited. The vesting is contingent upon certain conditions (as defined in the award agreement under the Equity Incentive Plan) that, as of December 31, 2021, had not been satisfied and were not considered probable. Therefore, we have not recognized compensation cost associated with the performance-vesting awards. These awards were valued using a Monte Carlo simulation assuming a Geometric Brownian Motion in a risk-neutral framework and using the following assumptions:


	Year Ended
	December 31, 2021
Expected life of awards (in years)		3
Expected volatility		70.00	%
Risk-free interest rate		0.29	%

A summary of performance-vesting restricted stock activity under the Successor Equity Incentive Plan as of December 31, 2021 and changes during the period from April 24, 2021 through December 31, 2021 is as follows:


	Number of Awards		Weighted -Average Grant Date Fair Value Per Share
Nonvested awards at April 24, 2021		—	$	—
Granted		777,777	$	6.89
Vested		—	$	—
Cancelled		—	$	—
Forfeited		—	$	—
Nonvested awards at December 31, 2021		777,777	$	6.89

Predecessor Plan

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. RSUs under the Predecessor Equity Plan were issued with performance-vesting or time-vesting features. Except for RSUs issued to our Chief Executive Officer, RSUs were not participating securities, and the holders of such awards had no right to receive regular dividends if or when declared. However, we have not paid a dividend to stockholders since 2015.

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 RSUs and/or SARs, were canceled. Any remaining outstanding awards under the Predecessor Equity Plan were cancelled on the Effective Date.

Total compensation cost recognized for all awards under the Predecessor Equity Plan for the years ended December 31, 2020 and 2019 was $5.6 million and $6.2 million, respectively. Tax benefits recognized for the years ended December 31, 2020 and 2019 related thereto were $0.2 million and $0.5 million, respectively. Due to the cancellation of the awards under the Predecessor Equity Plan described above, there is no remaining compensation cost to be recognized in future periods related to unvested or outstanding awards.

Time-Vesting Awards

SARs. SARs awarded under the Predecessor Equity Plan generally vested immediately and expired in ten years. The exercise price per share of SARs awarded under the Predecessor Equity Plan could not be less than the fair market value of our common stock on the date of grant.

The fair value of SARs granted under the Predecessor Equity Plan (or its predecessor) during the years ended December 31, 2020 and 2019 was estimated using the Black Scholes pricing model with the following weighted average assumptions:


	Year Ended December 31,
	2020			2019
Expected life of SARs (in years)		8			7
Expected volatility		127.65	%		39.35	%
Risk-free interest rate		1.85	%		2.11	%

The expected life of SARs and expected volatility were based on historical data. Risk-free interest rates were determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected life of the SARs.

A summary of SARs activity under the Predecessor Equity Plan as of April 23, 2021 and changes during the period from January 1, 2021 through April 23, 2021 is as follows:


	Number of Awards			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (Years)		Aggregate Intrinsic Value (In Thousands)
Awards outstanding at January 1, 2021		612,700		$	43.84
Granted		—		$	—
Cancelled		(529,400	)	$	56.57
Expired		(83,300	)	$	63.55
Awards outstanding at April 23, 2021		—		$	—		—	$	—
Awards exercisable at April 23, 2021		—		$	—		—	$	—

The weighted-average grant date fair values per share of awards granted during the Predecessor years ended December 31, 2020 and 2019 were $6.64 and $3.75, respectively.

RSUs. In 2019, we granted an aggregate of 310,700 time-vesting RSUs, with one-half set to vest two years from the date of grant and the remaining 50% to vest three years from the date of grant, conditioned upon continued employment through the applicable vesting date. The fair value of time-vesting RSUs granted under the Predecessor Equity Plan was estimated based on the fair market value of our common stock on the date of grant.

A summary of activity for time-vesting RSUs under the Predecessor Equity Plan as of April 23, 2021 and changes during the period from January 1, 2021 through April 23, 2021 is as follows:


	Number of Awards			Weighted -Average Grant Date Fair Value Per Share
Nonvested awards at January 1, 2021		11,000		$	11.49
Granted		—		$	—
Vested		(6,175	)	$	12.09
Cancelled		(4,825	)	$	10.49
Forfeited		—		$	—
Nonvested awards at April 23, 2021		—		$	—

The total fair value of time-vesting RSUs that vested during the Predecessor periods from January 1, 2021 through April 23, 2021, and the years ended December 31, 2020 and 2019 was $0, $0.2 million and $1.9 million, respectively.

Performance-Vesting Awards

RSUs. In 2019, we granted an aggregate of 190,634 performance-vesting RSUs which were set to vest upon achievement of certain performance goals as set forth in the individual award agreements over the three-year performance period beginning on January 1 in the year of grant. The fair value of performance-vesting RSUs granted under the Predecessor Equity Plan was estimated based on the fair market value of our common stock on the date of grant.

All performance-vesting RSUs under the Predecessor Equity Plan were cancelled or forfeited in 2020 and therefore, there was no activity during the year ended December 31, 2021. The total fair value of performance-vesting RSUs that vested during the Predecessor years ended December 31, 2020 and 2019 was $1.2 million and $2.3 million, respectively.

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, 2021, 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, 2021.

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, 2021, $5.9 million in trade receivables were considered past due by 30 days or more, of which $5.5 million were fully reserved for in previous years. The remaining $0.4 million were less than a year past due and considered collectible. For purposes of calculating our current estimate of credit losses at December 31, 2021 and 2020, all trade receivables 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, 2021 and 2020, including $0.1 million at both December 31, 2021 and 2020 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, 2021.

Assets measured at fair value are summarized below (in thousands).


	Successor
	December 31, 2021
	Fair Value Measurements Using										Predecessor
Nonrecurring fair value measurements:	Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Period from April 24, 2021 through December 31, 2021 (1)		Total Losses for Period from January 1, 2021 to April 23, 2021 (2)

Impaired assets (3)	$	—	$	—	$	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 (4)

Impaired assets (5)	$	—	$	—	$	1,000	$	1,000	$	842,016

(1)

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.

(2)

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.

(3)

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.

(4)

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.

(5)

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.

See Note 5 “Impairment of Assets.”

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, 2021 and 2020. 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).


	Successor				Predecessor
	December 31, 2021				December 31, 2020
	Fair Value		Carrying Value		Fair Value		Carrying Value
Exit Term Loans	$	100.0	$	100.0	$	—	$	—
First Lien Notes		86.2		86.1		—		—
3.45% Senior Notes due 2023		—		—		30.6		250.0
7.875% Senior Notes due 2025		—		—		61.3		500.0
5.70% Senior Notes due 2039		—		—		61.2		500.0
4.875% Senior Notes due 2043		—		—		91.9		750.0

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.

11. Prepetition Revolving Credit Facility, Senior Notes and Exit Debt

Prepetition Revolving Credit Facility

On October 2, 2018, Diamond Offshore Drilling, Inc., or DODI, as the U.S. borrower, and our subsidiary DFAC, as the foreign borrower, entered into a senior 5-year Revolving Credit Agreement with a syndicate of lenders and Wells Fargo Bank, National Association, as administrative agent, for general corporate purposes, including investments, acquisitions and capital expenditures. The maximum amount of borrowings available under the RCF was $950.0 million and it was scheduled to mature on October 2, 2023.

On the Petition Date, we had borrowings outstanding under our prepetition RCF aggregating $436.0 million. Upon commencement of the Chapter 11 Cases, which constituted an event of default under the RCF, the principal and interest under the RCF became immediately due and payable. Subsequently, as a result of the commencement of the Chapter 11 Cases, we received notification on April 28, 2020 that the commitments under the RCF had been reduced from $950.0 million to approximately $442.0 million. In January 2021, a $6.0 million financial letter of credit was drawn on by the beneficiary and converted to an adjusted base rate loan under the RCF, which resulted in total outstanding borrowings of $442.0 million under the RCF prior to the Effective Date.

On April 26, 2020, as a result of commencement of the Chapter 11 Cases, we ceased accruing interest on our borrowings under the RCF. As a result, we did not record $21.3 million of contractual interest expense related to outstanding borrowings under our RCF for the year ended December 31, 2020. Additionally, we wrote off $3.9 million in deferred arrangement fees associated with the RCF during the year ended December 31, 2020, which have been reported as “Reorganization items, net” in our Consolidated Statements of Operations.

The outstanding borrowings and accrued prepetition interest under the RCF were presented as “Liabilities subject to compromise” in the Predecessor’s Consolidated Balance Sheet at December 31, 2020. However, 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 “Liabilities subject to compromise” as such claims, including accrued interest since the Petition Date, would 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 and also recorded the unpaid post-petition interest not previously recognized. 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

At December 31, 2020, the Senior Notes were comprised of the following debt issues and were reported as “Liabilities subject to compromise” in the Predecessor’s Consolidated Balance Sheet (in thousands):


	Predecessor
	December 31,
	2020
3.45% Senior Notes due 2023	$	250,000
7.875% Senior Notes due 2025		500,000
5.70% Senior Notes due 2039		500,000
4.875% Senior Notes due 2043		750,000
Total Senior Notes, net	$	2,000,000

Upon commencement of the Chapter 11 Cases, we ceased accruing interest on the Senior Notes. 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 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 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, 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):


	Successor
	December 31,
	2021
Borrowings under Exit RCF	$	83,478
Exit Term Loans		99,034
First Lien Notes		83,729
Total Exit Debt, net	$	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, 2021, the aggregate annual maturity of the Successor Exit Debt, excluding net unamortized premium and debt issuance costs of $0.8 million and $3.3 million, respectively, was as follows (in thousands):


	Aggregate Principal Amount
Year Ending December 31,
2022	$	—
2023		—
2024		—
2025		—
2026		83,478
Thereafter		185,321
Total maturities of long-term debt	$	268,799

Exit Revolving Credit Agreement

On the Effective Date, the Company entered into the Exit RCF, which provides for a $400.0 million senior secured revolving credit facility, with a $100.0 million sublimit for the issuance of letters of credit thereunder, that 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, 2021, 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, 2021. At December 31, 2021, we had borrowings outstanding of $83.5 million under the Exit RCF, including $3.5 million in PIK Loans. In July 2021, we utilized $6.1 million for the issuance of a letter of credit in replacement of a previously existing letter of credit. The weighted average interest rate on the combined borrowings outstanding under the Exit RCF at December 31, 2021 was 5.35%.

At March 1, 2022, we had borrowings of $100.0 million outstanding under the Exit RCF, excluding the PIK Loans, and had utilized $6.1 million of the Exit RCF for the issuance of a letter of credit in replacement of a previously existing letter of credit. As of March 1, 2022, approximately $293.9 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, 2021, 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 $1.0 million, which are being amortized as interest expense over the stated maturity of the loans using the effective interest method. At December 31, 2021, we had Exit Term Loans outstanding of $100.0 million, which

accrue interest at 7.0% per annum, assuming a six-month LIBOR and cash interest payment option, and had an effective interest rate of 7.2% 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;

•

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;

•

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, 2021, 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 $2.5 million, which are being amortized as interest expense over the stated maturity of the notes using the effective interest method. At December 31, 2021, 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.

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 and finance leases for Well Control Equipment. 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 right-of-use 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 right-of-use lease 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 right-of-use 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):


	Successor			Predecessor
	December 31,			December 31,
	2021			2020
Operating Leases:
Other assets	$	38,834		$	154,796
Accrued liabilities		(15,998	)		(5,072	)
Other liabilities		(22,762	)		(23,476	)
Liabilities subject to compromise (1)		—			(112,646	)
Finance Leases:
Drilling and other property and equipment, net of accumulated depreciation		162,717			—
Current finance lease liabilities		(15,865	)		—
Noncurrent finance lease liabilities		(148,358	)		—

(1)

Balance at December 31, 2020 included current and noncurrent operating lease liabilities of $16.7 million and $95.9 million, respectively

Components of lease expense are as follows (in thousands):


	Successor		Predecessor
	Period from		Period from		Year Ended		Year Ended
	April 24, 2021 through		January 1, 2021 through		December 31,		December 31,
	December 31, 2021		April 23, 2021		2020		2019
Operating lease cost	$	11,754	$	11,799	$	35,964	$	35,752
Finance lease cost:
Amortization of ROU assets		11,854		—		—		—
Interest on lease liabilities		7,796		—		—		—
Short-term lease cost		199		101		832		3,414
Variable lease cost		1,237		598		1,465		504
Total lease cost	$	32,840	$	12,498	$	38,261	$	39,670

Supplemental information related to leases is as follows (in thousands, except weighted-average data):


	Successor			Predecessor
	Period from			Period from			Year Ended			Year Ended
	April 24, 2021 through			January 1, 2021 through			December 31,			December 31,
	December 31, 2021			April 23, 2021			2020			2019
Operating Leases:
Operating cash flows used	$	12,005		$	10,817		$	35,057		$	39,561
Right-of-use assets obtained in exchange for lease liabilities		19,064			1,076			10,645			26,248
Weighted-average remaining lease term (1)	4.4 years			5.9 years			5.6 years			6.7 years
Weighted-average discount rate (1)		6.53	%		6.89	%		8.94	%		8.68	%
Finance Leases:
Operating cash flows used	$	7,796		$	—		$	—		$	—
Financing cash flows used		9,845			—			—			—
Right-of-use assets obtained in exchange for lease liabilities		174,571			—			—			—
Weighted-average remaining lease term (1)	4.5 years			n/a			n/a			n/a
Weighted-average discount rate (1)		6.72	%	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, 2021 are as follows (in thousands):


	Operating Leases			Finance Leases			Total
2022	$	17,956		$	26,280		$	44,236
2023		8,056			26,280			34,336
2024		4,678			26,352			31,030
2025		3,403			26,280			29,683
2026		3,411			96,430			99,841
Thereafter		7,694			—			7,694
Total lease payments		45,198			201,622		$	246,820
Less: interest		(6,438	)		(37,399	)
Total lease liability	$	38,760		$	164,223

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. 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.

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 is considered 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 and resulting in realignment of substantially all our assets and operations under a wholly owned foreign subsidiary. Consequently, our management has determined that we will permanently reinvest foreign earnings of foreign subsidiaries.

100

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 tax 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.

In 2019, the Internal Revenue Service, or IRS, issued final regulations with respect to the calculation of the toll charge associated with the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries, or Transition Tax, in response to the Tax Cuts and Jobs Act enacted in 2017, commonly referred to as the Tax Reform Act. Based on the new regulations, we recorded a net tax benefit of $14.2 million in the second quarter of 2019, primarily to reverse a previously recorded uncertain tax position related to the Transition Tax. Consequently, our revised net tax benefit associated with the Tax Reform Act is $34.5 million, which now consists of (i) a $38.0 million charge relating to the one-time mandatory repatriation of previously deferred earnings of certain non-U.S. subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes and (ii) a $72.5 million credit resulting from the determination and re-measurement of our net U.S. deferred tax liabilities at the lower corporate income tax rate.

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, 2021, 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, 2021.

The components of income tax expense (benefit) are as follows (in thousands):


	Successor			Predecessor
	Period from			Period from
	April 24, 2021 through			January 1, 2021 through			Year Ended December 31,
	December 31, 2021			April 23, 2021			2020			2019
Federal – current	$	3,645		$	171		$	(11,844	)	$	(13,810	)
State – current		—			—			(12	)		19
Foreign – current		1,491			(3,681	)		9,898			25,899
Total current		5,136			(3,510	)		(1,958	)		12,108
Federal – deferred		(6,742	)		(30,955	)		(7,431	)		(67,015	)
Foreign – deferred		3,260			(4,939	)		(11,797	)		10,107
Total deferred		(3,482	)		(35,894	)		(19,228	)		(56,908	)
Total	$	1,654		$	(39,404	)	$	(21,186	)	$	(44,800	)

101

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			Period from
	April 24, 2021 through			January 1, 2021 through			Year Ended December 31,
	December 31, 2021			April 23, 2021			2020			2019
(Loss) income before income tax expense:
U.S.	$	(1,048	)	$	686,202		$	(336,880	)	$	(339,072	)
Foreign		(174,642	)		(2,687,595	)		(939,210	)		(62,942	)
	$	(175,690	)	$	(2,001,393	)	$	(1,276,090	)	$	(402,014	)
Expected income tax benefit at federal statutory rate	$	(36,895	)	$	(420,292	)	$	(267,979	)	$	(84,423	)
Effect of tax rate changes		9,871			—			(7,003	)		(74,168	)
Reorganization items		266			(225,563	)		7,871			—
Post-petition interest expense		—			(6,771	)		(16,778	)		—
Effect of foreign operations		79,600			163,236			136,262			3,129
Valuation allowance		(45,919	)		515,421			17,331			11,650
Uncertain tax positions, settlements and adjustments relating to prior years		(7,220	)		(67,626	)		107,148			96,960
Other		1,951			2,191			1,962			2,052
Income tax benefit	$	1,654		$	(39,404	)	$	(21,186	)	$	(44,800	)

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):


	Successor			Predecessor
	December 31,			December 31,
	2021			2020
Deferred tax assets:
Net operating loss carryforwards, or NOLs	$	226,022		$	285,910
Foreign tax credits		29,243			34,089
Disallowed interest deduction		70,492			66,395
Worker’s compensation and other current accruals		5,150			5,644
Deferred deductions		6,869			7,749
Deferred revenue		6,282			11,240
Operating lease liability		33,815			9,156
Property, plant and equipment		334,757			—
Other		4,971			12,967
Total deferred tax assets		717,601			433,150
Valuation allowance		(673,452	)		(203,950	)
Net deferred tax assets		44,149			229,200
Deferred tax liabilities:
Property, plant and equipment		—			(239,576	)
Mobilization		—			(7,422	)
Right-of-use assets		(33,117	)		(9,603	)
Other		(871	)		(937	)
Total deferred tax liabilities		(33,988	)		(257,538	)
Net deferred tax asset (liability)	$	10,161		$	(28,338	)

102

Net Operating Loss Carryforwards. As of December 31, 2021, we recorded a deferred tax asset of $226.0 million for the benefit of NOL carryforwards, comprised of $64.0 million related to our U.S. losses and $162.0 million related to our international operations. Approximately $131.1 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $94.9 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 2023 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, 2021, we recorded a deferred tax asset of $29.2 million for the benefit of foreign tax credits in the U.S. Of this balance, $2.7 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 2022 to 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, 2021, valuation allowances aggregating $673.5 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			For the Period
	April 24, 2021			January 31, 2021			For the Year Ended
	through			through			December 31,
	December 31, 2021			April 23, 2021			2020			2019
Balance, beginning of period	$	(26,678	)	$	(214,626	)	$	(118,884	)	$	(55,943	)
Additions for current year tax positions		(3,553	)		—			(100,780	)		(85,970	)
Additions for prior year tax positions		(1,424	)		(1,282	)		(1,559	)		(2,113	)
Reductions for prior year tax positions		1,730			187,389			2,944			23,267
Reductions related to statute of limitation expirations		8,777			1,841			3,653			1,875
Balance, end of period	$	(21,148	)	$	(26,678	)	$	(214,626	)	$	(118,884	)

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 and April 23, 2021, further clarification on the treatment of depreciable property resulted in the reversal of the previously recorded amount of $187.0 million. 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. The $23.3 million reduction in 2019 for prior year tax positions was mainly due to the reversal of an uncertain tax position recorded for the one-time mandatory repatriation provision of the Tax Cuts and Jobs Act enacted in 2017, following final regulations issued by the IRS in June 2019.

103

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. On December 31, 2020, $0.6 million, $193.2 million and $56.3 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, 2021, 2020 and 2019, $48.9 million, $249.0 million and $148.8 million, respectively, would affect the effective tax rates if recognized.

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. At December 31, 2020, the amount of accrued interest and penalties related to uncertain tax positions was $6.0 million and $19.0 million, respectively.

Interest expense (benefit) recognized 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 years ended December 31, 2020 and 2019 related to uncertain tax positions was $1.8 million, $0.1 million, $1.9 million and $1.0 million, respectively. Penalties recognized 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 years ended December 31, 2020 and 2019 related to uncertain tax positions were $0.04 million, $(0.4) million, $1.1 million and $0.3 million, respectively.

We expect the statutes of limitation for the 2014 through 2019 tax years to expire in 2022 for various of our subsidiaries operating in Australia, Malaysia, Mexico, the U.S. and in the U.K. We anticipate that the related unrecognized tax benefit will decrease by $10.3 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 2009 to 2021. We are currently under examination or contesting assessments in Australia, Brazil, Egypt, Equatorial Guinea, Malaysia, Mexico, 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.

18. Segments and Geographic Area Analysis

Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, 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.

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, 2021, our active drilling rigs were located offshore five 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):


	Successor
	Period from April 24, 2021 through December 31, 2021
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	194,912	$	55,471	$	250,383
Australia		95,601		15,132		110,733
United Kingdom		55,245		3,859		59,104
Senegal		48,758		10,110		58,868
Brazil		42,215		—		42,215
Myanmar		28,597		6,166		34,763
Total	$	465,328	$	90,738	$	556,066


	Predecessor
	Period from January 1, 2021 through April 23, 2021
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	93,215	$	7,048	$	100,263
Australia		17,031		4,697		21,728
United Kingdom		27,967		2,300		30,267
Brazil		3,421		—		3,421
Myanmar		11,730		1,970		13,700
Total	$	153,364	$	16,015	$	169,379


	Predecessor
	Year Ended December 31, 2020
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States	$	321,150	$	13,262		$	334,412
Australia		63,876		13,271			77,147
United Kingdom		112,121		8,929			121,050
Brazil		155,436		(18	)		155,418
Malaysia (1)		40,170		5,490			45,660
Total	$	692,753	$	40,934		$	733,687

(1)

Revenue earned by the Ocean Monarch during a standby period in Malaysia while awaiting clearance to begin operations in Myanmar waters.

106


	Predecessor
	Year Ended December 31, 2019
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	507,759	$	7,881	$	515,640
Australia		85,932		23,710		109,642
United Kingdom		149,724		14,036		163,760
Brazil		191,519		83		191,602
Total	$	934,934	$	45,710	$	980,644

The following table presents the locations of our long-lived tangible assets by country as of December 31, 2021, 2020 and 2019. 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).


	Successor		Predecessor
	December 31,		December 31,
	2021 (1) (2)		2020 (2)		2019
Drilling and other property and equipment, net:
United States	$	559,288	$	2,162,488	$	2,227,934
International:
Senegal		188,694		—		—
Spain		142,930		686,436		—
Australia		106,173		722,389		570,964
United Kingdom		98,338		248,500		1,061,585
Brazil		76,383		87,543		883,607
Myanmar		2,258		207,451		—
Singapore		—		5,819		404,420
Other countries (3)		1,831		2,183		4,318
		616,607		1,960,321		2,924,894
Total	$	1,175,895	$	4,122,809	$	5,152,828

(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)

Countries with long-lived assets that individually comprise less than 5% of total drilling and other property and equipment, net of accumulated depreciation.

107

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 period from April 24, 2021 through December 31, 2021 and the Predecessor periods from January 1, 2021 through April 23, 2021 and the years ended December 31, 2020 and 2019 that contributed more than 10% of our total revenues are as follows:


	Successor			Predecessor
	Period from			Period from
	April 24, 2021 through			January 1, 2021 through			Year Ended December 31,
Customer	December 31, 2021			April 23, 2021			2020			2019
BP		25.4	%		39.8	%		20.6	%		3.1	%
Woodside		22.4	%		0.5	%		7.0	%		3.6	%
Occidental		11.5	%		21.4	%		20.1	%		20.6	%
Petróleo Brasileiro S.A.		7.6	%		2.0	%		21.2	%		19.5	%
Shell		5.1	%		9.2	%		10.1	%		5.2	%
Hess Corporation		—			—			10.7	%		28.9	%

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

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, 2021. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2021.

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, 2021. 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, 2021, 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 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 will be provided in an amendment to this Annual Report on Form 10-K/A to be filed no later than May 2, 2022.

Information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A to be filed no later than May 2, 2022.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A to be filed no later than May 2, 2022.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A to be filed no later than May 2, 2022.

** 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.

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 March 7, 2022.

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.


Delaware	76-0321760
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)


Attributes
DP	=	Dynamically Positioned/Self-Propelled	MPD	=	Managed Pressure Drilling equipped
7R	=	2 Seven ram blow out preventers	15K	=	15,000 psi well control system
6R	=	Six ram blow out preventer


	January 1, 2022 (1)		October 1, 2021 (1)(2)		January 1, 2021 (2)
Contract Drilling Backlog	$	1,191	$	1,034	$	1,187


	Successor			Predecessor			Predecessor
	Period from			Period from			Year Ended
	April 24, 2021 through			January 1, 2021 through			December 31,
	December 31, 2021			April 23, 2021			2020
REVENUE-EARNING DAYS (1)		2,250			724			2,936
UTILIZATION (2)		74	%		53	%		59	%
AVERAGE DAILY REVENUE (3)	$	206,800		$	211,800		$	227,000

CONTRACT DRILLING REVENUE	$	465,328		$	153,364		$	692,753
REVENUE RELATED TO REIMBURSABLE EXPENSES		90,738			16,015			40,934
TOTAL REVENUES	$	556,066		$	169,379		$	733,687
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	364,539		$	181,626		$	618,553
REIMBURSABLE EXPENSES	$	89,284		$	15,477		$	38,900

OPERATING INCOME (LOSS)
Contract drilling services, net	$	100,789		$	(28,262	)	$	74,200
Reimbursable expenses, net		1,454			538			2,034
Depreciation		(68,504	)		(92,758	)		(320,085	)
General and administrative expense		(53,494	)		(15,036	)		(56,925	)
Impairment of assets		(132,449	)		(197,027	)		(842,016	)
Restructuring and separation costs		—			—			(17,724	)
Gain on disposition of assets		1,024			5,486			7,375
Total Operating Loss	$	(151,180	)	$	(327,059	)	$	(1,153,141	)
Other income (expense):
Interest income		3			30			484
Interest expense		(26,180	)		(34,827	)		(42,585	)
Foreign currency transaction loss		(997	)		(172	)		(4,498	)
Reorganization items, net		(8,088	)		(1,639,763	)		(76,910	)
Other, net		10,752			398			560
Loss before income tax (expense) benefit		(175,690	)		(2,001,393	)		(1,276,090	)
Income tax (expense) benefit		(1,654	)		39,404			21,186
NET LOSS	$	(177,344	)	$	(1,961,989	)	$	(1,254,904	)


	Payments Due By Period
Contractual Obligations (1)	Total		2022		2023-2024		2025-2026		Thereafter
Exit Term Loan (principal and interest) (2)	$	139,034	$	7,097	$	14,194	$	14,194	$	103,549
First Lien Notes (principal and interest) (3)		132,316		9,177		17,985		16,143		89,011
Exit RCF borrowings (4)		103,866		4,824		9,413		89,629		—
Well Control Equipment services agreement (5)		137,232		24,696		47,388		65,148		—
Finance leases (6)		201,622		26,280		52,632		122,710		—
Operating leases (6)		45,456		18,195		12,750		6,817		7,694
Total obligations	$	759,526	$	90,269	$	154,362	$	314,641	$	200,254


Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	☑	Smaller reporting company	☐

Emerging growth company	☐


As of March 1, 2022	Common Stock, $0.0001 par value per share	100,074,948 shares


Part I
Item 1.	Business	3

Item 1A.	Risk Factors	9

Item 1B.	Unresolved Staff Comments	27

Item 2.	Properties	27

Item 3.	Legal Proceedings	28

Item 4.	Mine Safety Disclosures	28

Part II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29

Item 6.	[Reserved]	29

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 8.	Financial Statements and Supplementary Data	51

	Consolidated Financial Statements	55

	Notes to Consolidated Financial Statements	60

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	109

Item 9A.	Controls and Procedures	109

Item 9B.	Other Information	109

Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	110

Part III
Item 10.	Directors, Executive Officers and Corporate Governance	111

Item 11.	Executive Compensation	111

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	111

Item 13.	Certain Relationships and Related Transactions, and Director Independence	111

Item 14.	Principal Accounting Fees and Services	111

Part IV
Item 15.	Exhibits and Financial Statement Schedules	112

Item 16.	Form 10-K Summary	114

Signatures		115


													Accumulated
							Additional						Other									Total
	Common Stock						Paid-In			Retained			Comprehensive			Treasury Stock						Stockholders’
	Shares			Amount			Capital			Earnings			Gains (Losses)			Shares			Amount			Equity
January 1, 2019 (Predecessor)		144,384		$	1,444		$	2,018,143		$	1,769,415		$	21			6,945		$	(204,370	)	$	3,584,653
Net loss		—			—			—			(357,214	)		—			—			—			(357,214	)
Stock-based compensation, net of tax		398			4			6,204			—			—			133			(1,398	)		4,810
Net loss on derivative financial instruments		—			—			—			—			(7	)		—			—			(7	)
Net loss on investments		—			—			—			—			(32	)		—			—			(32	)
December 31, 2019		144,782		$	1,448		$	2,024,347		$	1,412,201		$	(18	)		7,078		$	(205,768	)	$	3,232,210
Net loss		—			—			—			(1,254,904	)		—			—			—			(1,254,904	)
Stock-based compensation, net of tax		482			5			5,632			—			—			132			(395	)		5,242
Net gain on derivative financial instruments		—			—			—			—			18			—			—			18
December 31, 2020		145,264			1,453			2,029,979			157,297			—			7,210			(206,163	)		1,982,566
Net loss		—			—			—			(1,961,989	)					—			—			(1,961,989	)
Cancellation of Predecessor equity		(145,264	)		(1,453	)		(2,029,979	)		1,804,692						(7,210	)		206,163			(20,577	)
April 23, 2021 (Predecessor)		—		$	—		$	—		$	—		$	—			—		$	—		$	—


Issuance of Successor equity		100,000			10			934,800			—			—			—			—			934,810
April 24, 2021 (Successor)		100,000		$	10		$	934,800		$	—		$	—			—		$	—		$	934,810
Net loss		—			—			—			(177,344	)		—			—			—			(177,344	)
Stock-based compensation, net of tax		75			—			10,239			—			—			—			—			10,239
December 31, 2021 (Successor)		100,075		$	10		$	945,039		$	(177,344	)	$	—			—		$	—		$	767,705


(1) Financial Statements	Page

Report of Independent Registered Public Accounting Firm (PCAOB ID 00034)	51
Consolidated Balance Sheets	55
Consolidated Statements of Operations	56
Consolidated Statements of Comprehensive Income or Loss	57
Consolidated Statements of Stockholders’ Equity	58
Consolidated Statements of Cash Flows	59
Notes to Consolidated Financial Statements	60


Exhibit No.	Description

2.1	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).

3.1	Third Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on April 29, 2021).

3.2	Second Amended and Restated Bylaws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K filed on April 29, 2021).

4.1	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).

10.1	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).

10.2	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+	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).

10.9+	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+	Diamond Offshore Drilling, Inc. Severance Plan (incorporated by reference to Exhibit 10.9 to our Current Report on Form 8-K filed on April 29, 2021).

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+	Employment Agreement, dated as of March 20, 2020, between Diamond Offshore Drilling, Inc. and Marc Edwards (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on March 23, 2020).

10.17+	Side Letter, dated April 22, 2021, between Diamond Offshore Drilling, Inc. and Marc Edwards (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K filed on April 29, 2021).

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+	Settlement Agreement, dated December 29, 2021, by and among Diamond Offshore Drilling, Inc., Avenue Capital Management II, L.P. and Avenue Energy Opportunities Fund II AIV, L.P.(incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on December 30, 2021).

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, 2021, formatted in Inline XBRL (included with the Exhibit 101 attachments).


	DIAMOND OFFSHORE DRILLING, INC.

	By:	/s/ DOMINIC A. SAVARINO
		Dominic A. Savarino
		Chief Financial Officer


Signature	Title	Date

/s/ BERNIE WOLFORD, JR.	Director, President and Chief Executive Officer	March 7, 2022
Bernie Wolford, Jr.	(Principal Executive Officer)

/s/ DOMINIC A. SAVARINO	Senior Vice President and Chief Financial Officer	March 7, 2022
Dominic A. Savarino	(Principal Financial Officer and Principal Accounting Officer)

/s/ NEAL P. GOLDMAN	Chairperson of the Board	March 7, 2022
Neal P. Goldman

/s/ JOHN H. HOLLOWELL	Director	March 7, 2022
John H. Hollowell

/s/ RAJ IYER	Director	March 7, 2022
Raj Iyer

/s/ ANE LAUNY	Director	March 7, 2022
Ane Launy

/s/ PATRICK CAREY LOWE	Director	March 7, 2022
Patrick Carey Lowe

/s/ ADAM C. PEAKES	Director	March 7, 2022
Adam C. Peakes