EDGAR 10-K Filing

Company CIK: 949039
Filing Year: 2024
Filename: 949039_10-K_2024_0000950170-24-022282.json

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ITEM 1. BUSINESS
Item 1. Business.
General
Diamond Offshore Drilling, Inc., incorporated in Delaware in 1989, provides contract drilling services to the energy industry around the globe with a fleet of 13 offshore drilling rigs, consisting of four owned drillships, seven owned semisubmersible rigs and two managed rigs. See “- Rig Management and Marketing Services” and “- Our Fleet - Fleet Status.”
Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries.
Reorganization and Chapter 11 Proceedings
On April 26, 2020 (or the Petition Date), Diamond Offshore Drilling, Inc. (or the Company) and certain of its direct and indirect subsidiaries (which we refer to, together with the Company, as the Debtors) commenced voluntary cases (or the Chapter 11 Cases) for relief under chapter 11 (or Chapter 11) of title 11 of the United States Code 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. 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.
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 10 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria for and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board (or FASB) Accounting Standards Codification (or ASC) Topic 852, Reorganizations (or ASC 852), which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date.
Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. In addition, as a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the period after April 23, 2021 will not be comparable with the financial statements prior to and including April 23, 2021. References to “Successor” refer to the Company and its financial position and results of operations after the Effective Date (or the years ended December 31, 2023 and 2022 and the period from April 24, 2021 to December 31, 2021). References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Effective Date (or from January 1, 2021 to April 23, 2021).
See Note 2 “Chapter 11 Proceedings” to our Consolidated Financial Statements included in Item 8 of this report.
Our Fleet
Our fleet enables us to offer services in the floater market on a worldwide basis. A floater rig is a type of mobile offshore drilling rig that floats and does not rest on the seafloor. This asset class includes semisubmersible rigs and self-propelled drillships.
Semisubmersible rigs are comprised of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom. Semisubmersibles hold position while drilling either by use of a set of small propulsion units or thrusters that provide dynamic positioning (or DP) to keep the rig on location, or with anchors tethered to the seabed to moor the rig. Although DP semisubmersibles are generally self-propelled, such rigs may be moved long distances with the assistance of tug boats. Non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between locations.
A drillship is an adaptation of a ship-shaped maritime vessel that is designed and constructed to carry out drilling operations by means of a derrick with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drill site through the use of a DP system.
Fleet Status
The following table presents additional information regarding our fleet at February 2, 2024:
Rig Type and Name
Rated Water
Depth
(in feet)(a)
Attributes
Year Built/
Redelivered (b)
Current
Location (c)
Customer or
standby status (d)
DRILLSHIPS (4):
Ocean BlackLion
12,000
DP; MPD; 7R; 15K
GOM
BP
Ocean BlackRhino
12,000
DP; 7R; 15K
Senegal
Woodside
Ocean BlackHornet
12,000
DP; MPD; 7R; 15K
GOM
BP
Ocean BlackHawk
12,000
DP; MPD; 7R; 15K
GOM
Oxy
SEMISUBMERSIBLES (7) (e):
Ocean GreatWhite (f)
10,000
DPM; 6R; 15K
North Sea/U.K.
BP
Ocean Courage
10,000
DP; 6R; 15K
Brazil
Petrobras
Ocean Endeavor
10,000
15K
North Sea/U.K.
Shell
Ocean Apex
6,000
15K
Australia
Inpex
Ocean Onyx
6,000
15K
Malaysia
Cold Stacked
Ocean Valiant
5,500
15K
North Sea/U.K.
Cold Stacked
Ocean Patriot
3,000
15K
North Sea/U.K.
Warm Stacked; Serica
MANAGED RIGS (2) (g):
West Auriga
10,000
DP; MPD; 15K
GOM
BP
West Vela
10,000
DP; MPD; 15K
GOM
Beacon
Attributes
DP
=
Dynamically Positioned/Self-Propelled
7R
=
Two seven-ram blow out preventer
DPM
=
Dynamically Positioned/Self-Propelled with mooring capabilities
6R
=
Six-ram blow out preventer
MPD
=
Managed Pressure Drilling equipped
15K
=
15,000 psi well control system
(a)Rated water depth for drillships and semisubmersibles reflects the maximum water depth in which a floating rig has been designed for drilling operations. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on various conditions (including, but not limited to, weather and sea conditions).
(b)Represents year rig was built and originally placed in service or year rig was redelivered with significant enhancements that enabled the rig to be classified within a different floater category than originally constructed.
(c)GOM means U.S. Gulf of Mexico.
(d)For ease of presentation in this table, customer names have been shortened or abbreviated. Warm Stacked is used to describe a rig that is idled (not contracted) and maintained in a “ready” state with a crew sized to enable the rig to be quickly placed into service when contracted. Cold Stacked is used to describe an idled rig for which steps have been taken to preserve the rig and reduce certain costs, such as crew costs and maintenance expenses. Depending on the amount of time that a rig is cold stacked, significant expenditures may be required to return the rig to a “ready” state.
(e)The Ocean Monarch is actively marketed for sale and has been excluded from our active fleet.
(f)On February 1, 2024, the Ocean GreatWhite, reported an equipment incident while on location in the North Sea. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Recent Event” in Item 7 of this report.
(g)Rigs owned by and managed on behalf of Seadrill Limited (or Seadrill). See “-Rig Management and Marketing Services.”
Markets
The principal markets for our offshore contract drilling services are:
•the Gulf of Mexico, including the United States, or U.S., and Mexico;
•Canada;
•South America, principally offshore Brazil;
•Australia and Southeast Asia;
•Europe, principally offshore the United Kingdom, or U.K.;
•East and West Africa; and
•the Mediterranean.
We actively market our rigs worldwide. From time to time, our fleet operates in various other markets throughout the world. See Note 15 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.
Offshore Contract Drilling Services
Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through a competitive bid process, although it is not unusual for us to be awarded drilling contracts following direct negotiations. Our drilling contracts generally provide for a basic dayrate regardless of whether or not drilling results in a productive well. Drilling contracts generally also provide for reductions in rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate contracts may also provide us the ability to earn an incentive bonus from our customer based upon performance.
The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, which we refer to as a well-to-well contract, or a fixed period of time, which we refer to as a term contract. Our drilling contracts may be terminated by the customer in the event the drilling unit is destroyed or lost, or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to events beyond the control of either party to the contract. Certain of our contracts also permit the customer to terminate the contract early by giving notice; in most circumstances this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally subject to mutually agreeable terms and rates at the time of the extension. In periods of decreasing demand for offshore rigs, drilling contractors may prefer longer term contracts to preserve dayrates at existing levels and ensure utilization, while customers may prefer shorter contracts that allow them to more quickly obtain the benefit of declining dayrates. Moreover, drilling contractors may accept lower dayrates in a declining market in order to obtain longer-term contracts and add backlog. Conversely, in periods of rising demand for offshore rigs, contractors may prefer shorter contracts that allow them to more quickly profit from increasing dayrates, while customers with reasonably definite drilling programs may prefer longer term contracts to maintain dayrate prices at a consistent level. See “Risk Factors - Risks Related to Our Business and Operations - We may not be able to renew or replace expiring contracts for our rigs” and “Risk Factors - Risks Related to Our Business and Operations - Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us,” in Item 1A of this report. For a discussion of our contract backlog, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contract Drilling Backlog” in Item 7 of this report.
Rig Management and Marketing Services
In May 2021, we entered into an arrangement with an offshore drilling company whereby we would provide management and marketing services (or the MMSA) for certain of their rigs. The MMSA provided for (i) a daily fixed fee based on status of the drilling rig, (ii) marketing fees based on a percentage of the earned dayrate of a drilling contract secured by us on behalf of the rig owner, (iii) a variable management fee and (iv) reimbursement of direct cost incurred.
We may enter certain drilling contracts directly with a customer. We are considered principal or agent for these transactions and recognize revenue under the terms of the contract. In addition, we charter the related drilling rig from the rig owner to satisfy our performance obligations under the contract. We have determined that the arrangement to charter the rig is an operating lease. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contract Drilling Backlog” in Item 7 of this report and Note 3 “Revenue from Contracts with Customers - Revenues Related to Managed Rigs” to our Consolidated Financial Statements in Item 8 of this report.
The marketing arrangement for both rigs was terminated in 2023, and the charter agreement for the West Auriga was terminated in 2024. The West Auriga is expected to be returned to the rig owner upon completion of its drilling contract during first quarter of 2024.
Customers
We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, we performed services for nine, seven, eight and ten different customers, respectively.
Our most significant customers during these periods were as follows:
Successor
Predecessor
Year Ended
Period from
Period from
December 31,
April 24, 2021 through
January 1, 2021 through
2023 (1)
2022 (1)
December 31, 2021 (1)
April 23, 2021
BP
48.4
%
33.1
%
25.4
%
39.8
%
Woodside
21.5
%
29.7
%
22.4
%
0.5
%
Oxy
2.9
%
3.9
%
11.5
%
21.4
%
(1)Excludes revenues, primarily reimbursable revenue, attributable to the MMSA with Seadrill of $8.8 million, $58.0 million and $45.3 million earned during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021, respectively. See “- Rig Management and Marketing Services.”
No other customer accounted for 10% or more of our annual total consolidated revenues during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021. See “Risk Factors - Risks Related to Our Business and Operations - Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition” and “Risk Factors - Risks Related to Our Business and Operations - Our customer base is concentrated” in Item 1A of this report.
Backlog
As of January 1, 2024, our contract backlog was an aggregate $1.4 billion attributable to twelve customers, compared to $1.8 billion as of January 1, 2023 attributable to ten customers. For the five-year period from 2024 to 2028, $1.1 billion (or 78%) of our contracted backlog as of January 1, 2024 was attributable to future operations with four customers, including one customer contracted for four rigs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Contract Drilling Backlog” in Item 7 of this report. See “Risk Factors - Risks Related to Our Business and Operations - We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized” in Item 1A of this report.
Competition
Based on industry data, as of the date of this report, there are approximately 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 market remains very competitive. See “Risk Factors - Risks Related to Our Business and Operations - Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition” in Item 1A of this report.
Governmental Regulation and Environmental Matters
Our operations are subject to numerous international, foreign, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use. See “Risk Factors - Regulatory and Legal Risks - We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs,” “Risk Factors - Environmental, Social and Governance Risks - Any future regulations relating to greenhouse gases and climate change could have a material adverse effect on our business” and “Risk Factors - Regulatory and Legal Risks - If we, or our customers, are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations” in Item 1A of this report.
Human Capital
Employees
As of December 31, 2023, we managed a global workforce of approximately 2,140 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, 2023, more than half of our global workforce had been employed by us for five years or more, with an average tenure of approximately 10 years.
Core Values and Culture
Our global culture is shaped by our Values & Behaviors:
•Take Ownership - Run to the challenge; deliver on what you promise.
•Go Beyond - Solve tomorrow’s problems today; make it better than you found it.
•Have Courage - Challenge conventional thinking; speak up, even when it’s tough.
•Exercise Care - Respect that every action has consequences; never cut corners.
•Win Together - Learn from each other; share success; champion a “Culture of We.”
These core values establish the foundation for our culture and represent the key expectations we have of our employees. Our commitment to Health, Safety and the Environment (or HSE) applies throughout our business. In addition, we recognize the importance of identifying, assessing and promoting Environmental, Social and Governance (or ESG) issues as a fundamental part of conducting business.
Along with our core values, we expect our employees to act in accordance with our Code of Business Conduct and Ethics, which we refer to as our Code of Conduct. Our Code of Conduct covers various topics including legal compliance, conflicts of interest, accuracy of financial reporting and disclosure, confidentiality, discrimination and harassment, anti-corruption, safety and health and reporting ethical violations. The Code of Conduct reflects our commitment to operating in a fair, honest, responsible and ethical manner and also provides direction for reporting complaints in the event of alleged violations of our policies (including through an anonymous hotline).
Talent Management and Training
We take a systemic approach to hiring, training and developing our employees. This includes creating goals aligned to company priorities and providing employees periodic feedback in order to assess and adjust individual performance. We also employ a succession planning process that identifies suitable candidates, and their development needs, for key positions in our company. We generally review the succession plan annually.
We provide a comprehensive training program that endeavors to ensure that employees on our rig crews receive position-specific training as an integral part of their career development. We utilize a competency verification program for establishing and verifying the knowledge, skills and abilities needed by each employee to perform their assigned job function in a safe and environmentally sound manner.
Safety
The safety of our employees and stakeholders is our highest priority. We pride ourselves on being an innovative leader in the development and implementation of sophisticated and efficient job safety programs. We not only try to work safely; we also strive to achieve zero incident operations, or ZIO, through our comprehensive safety initiatives. Achieving ZIO means operating at peak performance and completing each task without harm to our people, the environment or our equipment.
Information About Our Executive Officers
We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors (or Board) and serve at the discretion of our Board until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below.
Name
Age as of
January 31, 2024
Position
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
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.
Available Information
We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (or the Exchange Act), and accordingly file annual, quarterly and current reports on Forms 10-K, 10-Q and 8-K, respectively, any amendments to those reports and other information with the United States Securities and Exchange Commission (or SEC). Our SEC filings are available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The preceding Internet addresses and all other Internet addresses referenced in this report are for information purposes only and are not intended to be a hyperlink. Accordingly, no information found or provided at such Internet addresses or at our website in general (or at other websites linked to our website) is intended or deemed to be incorporated by reference into this report and such information should not be considered a part of this report or any other filing that we make with the SEC.
Disclosure of Material Non-Public Information
We announce material information through our filings with the SEC, press releases and/or public conference calls and webcasts. Based on guidance from the SEC, we may also use our website at www.diamondoffshore.com as a means of disclosing material financial information and other material non-public information and for complying with our disclosure obligations under Regulation FD. Such disclosures will be included on our website in the ‘Investors’ section. Accordingly, we encourage investors, the media and others interested in our company to monitor such portions of our website, in addition to following our SEC filings, press releases and public conference calls and webcasts.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
Our business is subject to a variety of risks and uncertainties, including those described below, that could have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects. You should carefully consider these risks when evaluating us and our securities. The following material risks and uncertainties are not the only ones facing our company. We are also subject to other risks and uncertainties not known to us or not described below as well as a variety of risks that affect many other companies generally that may also have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects.
Risk Factors Summary
The following is a summary of the principal risks that could adversely affect our business, operations and financial results.
Risks Related to Our Business and Operations
•The worldwide demand for drilling services has historically been dependent on the price of oil.
•Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical, is currently emerging from a protracted downturn and is significantly affected by many factors outside of our control.
•Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition.
•We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized.
•We may not be able to renew or replace expiring contracts for our rigs.
•Our customer base is concentrated.
•Our contract drilling expense includes fixed costs that will not decline in proportion to decreases in rig utilization and dayrates.
•We must make substantial capital and operating expenditures to reactivate, build, maintain and upgrade our drilling fleet.
•Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
•Any significant cyber-attack or other interruption in network security or the operation of critical information technology systems could materially disrupt our operations and adversely affect our business.
•Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on us.
•We rely on third-party suppliers, manufacturers and service providers to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction.
•Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability.
•Inflation may adversely affect our operating results and increase working capital investments required to
operate our business.
•The impact of public health threats, such as the COVID-19 pandemic, and efforts to mitigate the spread of such threats have adversely impacted, and could continue to adversely impact, our business, operations and financial results.
•Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility in how we manage our personnel.
•Failure to obtain and retain highly skilled personnel could hurt our operations.
•As part of our business strategy, we may pursue business opportunities that include acquisitions of businesses or drilling rigs, mergers or joint ventures or other investments, and such transactions would present various risks and uncertainties.
Financial and Tax Risks
•Our financial performance after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.
•Our Senior Secured Second Lien Notes and revolving credit agreement contain various restrictive covenants, limiting the discretion of our management in operating certain aspects of our business.
•Our variable rate indebtedness subjects us to interest rate risk that could have an adverse impact on us.
•The exercise of all or any number of the outstanding Emergence Warrants or the granting or vesting of stock-based awards will dilute the interests of the holders of our common stock.
•We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.
•Changes in tax laws and policies, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results.
•Our consolidated effective income tax rate may vary substantially from one reporting period to another.
•Changes in accounting principles and financial reporting requirements could adversely affect us.
Environmental, Social and Governance Risks
•Regulations relating to greenhouse gases and climate change could have a material adverse effect on our business.
•Consumer preference and increasing demand for alternative fuels and electric-powered vehicles may lead to reduced demand for contract drilling services.
•Increased focus on climate change, the environmental and social impacts of fossil fuel extraction and use and other ESG matters could result in additional costs or risks and adversely impact our business and reputation and our access to capital and ability to refinance our debt.
•Global energy supply may shift from our industry's basis, hydrocarbons, to non-hydrocarbon sources, including wind, solar, nuclear and hydroelectric, which, in turn, may adversely affect demand for our services.
Regulatory and Legal Risks
•We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs.
•If we, or our customers, are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations.
•Significant portions of our operations are conducted outside the U.S. and involve additional risks not associated with U.S. domestic operations.
•We may be subject to litigation and disputes that could have a material adverse effect on us.
For a more complete discussion of the material risks facing our business, see below.
Risks Related to Our Business and Operations
The worldwide demand for drilling services has historically been dependent on the price of oil.
Demand for our drilling services depends in large part upon the oil and natural gas industry’s offshore exploration and production activity and expenditure levels, which are directly affected by oil and gas prices and market expectations of potential changes in oil and gas prices. After a period of historical, high commodity prices, oil prices declined significantly, beginning in the second half of 2014, and resulted in a sharp decline in the demand for offshore drilling services, including services that we provide. The reduction in demand has had a material adverse effect on our results of operations and cash flows compared to periods before the decline. Although oil prices have increased from previous lows, the return of low oil prices could stall the recovery of our industry and would continue to have a material adverse effect on many of our customers and, therefore, demand for our services and our financial condition, results of operations and cash flows, including negative cash flows.
Oil prices have been, and are expected to continue to be, volatile and are affected by numerous factors beyond our control, including:
•worldwide supply and demand for oil and gas;
•the level of economic activity in energy-consuming markets;
•the worldwide economic environment and economic trends, including recessions and the level of international trade activity;
•the ability of the Organization of Petroleum Exporting Countries, and 10 other oil producing countries, including Russia and Mexico, or OPEC+, to set and maintain production levels and pricing;
•the level of production in non-OPEC+ countries, including U.S. domestic onshore oil production;
•civil unrest and the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities involving the Middle East, Russia, Myanmar, Senegal, other oil-producing regions or other geographic areas or further acts of terrorism in the U.S. or elsewhere, such as the current armed conflicts between Russia and Ukraine and Israel and Hamas;
•the cost of exploring for, developing, producing and delivering oil and gas, both onshore and offshore;
•the discovery rate of new oil and gas reserves;
•the rate of decline of existing and new oil and gas reserves and production;
•available pipeline and other oil and gas transportation and refining capacity;
•the ability of oil and gas companies to raise capital;
•weather conditions, including hurricanes, which can affect oil and gas operations over a wide area;
•natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;
•the policies of various governments regarding exploration and development of their oil and gas reserves;
•international sanctions on oil-producing countries, or the lifting of such sanctions;
•technological advances affecting energy consumption, including development and exploitation of alternative fuels or energy sources;
•laws and regulations relating to environmental or energy security matters, including those addressing alternative energy sources, the phase-out of fossil fuel vehicles or the risks of global climate change;
•domestic and foreign tax policy; and
•advances in exploration and development technology.
Although, historically, higher sustained commodity prices have generally resulted in increases in offshore drilling projects, short-term or temporary increases in the price of oil and gas will not necessarily result in an increase in offshore drilling activity or an increase in the market demand for our rigs. The timing of commitment to offshore activity in a cycle depends on project deployment times, reserve replacement needs, availability of capital and alternative options for resource development, among other things. Timing can also be affected by availability, access to, and cost of equipment to perform work.
Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical, is currently emerging from a protracted downturn and is significantly affected by many factors outside of our control.
Demand for our drilling services depends upon the level of offshore oil and gas exploration, development and production in markets worldwide, and those activities depend in large part on oil and gas prices, worldwide demand for oil and gas and a variety of political and economic factors. The level of offshore drilling activity is adversely affected when operators reduce or defer new investment in offshore projects, reduce or suspend their drilling budgets or reallocate their drilling budgets away from offshore drilling in favor of other priorities, such as renewable energy or land-based projects, which have reduced, and may in the future further reduce, demand for our rigs. As a result, our business and the oil and gas industry in general are subject to cyclical fluctuations.
As a result of the cyclical fluctuations in the market, there have been periods of lower demand, excess rig supply and lower dayrates, followed by periods of higher demand, shorter rig supply and higher dayrates. We cannot predict the timing or duration of such fluctuations. Periods of lower demand or excess rig supply intensify the competition in the industry and often result in periods of lower utilization and lower dayrates. During these periods, our rigs may not be able to obtain contracts for future work and may be idle for long periods of time or may be able to obtain work only under contracts with lower dayrates or less favorable terms. Additionally, prolonged periods of low utilization and dayrates have in the past resulted in, and may in the future result in, the recognition of further impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. See “-We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.”
Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition.
The offshore contract drilling industry remains highly competitive with numerous industry participants. Some of our competitors are larger companies, have larger or more technologically advanced fleets and have greater financial or other resources than we do. The drilling industry has experienced consolidation and may experience additional consolidation, which could create additional large competitors. Moreover, as a result of the reductions in demand for oil and natural gas services during the most recent industry downturn, 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.
In addition, during industry downturns like the one we are emerging from, rig operators may take lower dayrates and shorter contract durations to keep their rigs operational.
We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized.
Our customers may terminate our drilling contracts under certain circumstances, such as the destruction or loss of a drilling rig, our suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, excessive downtime for repairs, failure to meet minimum performance criteria (including customer acceptance testing) or, in some cases, due to other events beyond the control of either party.
In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods, often by tendering contractually specified termination amounts, which may not fully compensate us for the loss of the contract. In some cases, our drilling contracts may permit the customer to terminate the contract without cause, upon little or no notice or without making an early termination payment to us. During depressed market conditions, certain customers have utilized, and may in the future utilize, such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid
their obligations to us under circumstances where we believe we are in compliance with the contracts. Additionally, because of depressed commodity prices, restricted credit markets, economic downturns, changes in priorities, strategy or government regulations, customer consolidation or other factors beyond our control, a customer may no longer want or need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. For these reasons, customers have sought and may in the future seek to renegotiate the terms of our existing drilling contracts, terminate our contracts without justification or repudiate or otherwise fail to perform their obligations under our contracts. As a result of such contract renegotiations or terminations, our contract backlog has been and may in the future be adversely impacted. We might not recover any compensation (or any recovery we obtain may not fully compensate us for the loss of the contract) and we may be required to idle one or more rigs for an extended period of time. These results in some cases in the past have had, and may in the future have, a material adverse effect on our financial condition, results of operations and cash flows. See “- Our industry is highly competitive, with an oversupply of drilling rigs and intense price competition.”
We may not be able to renew or replace expiring contracts for our rigs.
Our ability to renew or replace expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers, at such times. Given the historically cyclical and highly competitive nature of our industry, we may not be able to renew or replace the contracts or we may be required to renew or replace expiring contracts or obtain new contracts at dayrates that are below existing dayrates, or that have terms that are less favorable to us, including shorter durations, than our existing contracts. Moreover, we may be unable to secure contracts for these rigs. Failure to secure contracts for a rig may result in a decision to cold stack the rig, which puts the rig at risk for impairment and may competitively disadvantage the rig as many customers have expressed a preference for ready or warm-stacked rigs over cold-stacked rigs. If a decision is made to cold stack a rig, our operating costs for the rig are typically reduced; however, we will incur additional costs associated with cold stacking the rig (particularly if we cold stack a newer rig, such as a drillship or other DP semisubmersible rig, for which cold-stacking costs are typically substantially higher than for an older non-DP rig). In addition, the costs to reactivate a cold-stacked rig may be substantial. See “- We must make substantial capital and operating expenditures to reactivate, build, maintain and upgrade our drilling fleet.”
Our customer base is concentrated.
We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2023, a single customer with operations in both the GOM and U.K. and another customer with operations offshore Senegal and Australia accounted for approximately 48% and 22%, respectively, of our total consolidated revenue for the year. In addition, the number of customers we have performed services for has declined from 35 in 2014 to eight in 2023. For the five-year period from 2024 to 2028, $1.1 billion (or 78%) of our current contracted backlog is attributable to future operations with ten customers, including one customer contracted for four rigs. The loss of a significant customer, whether due to economic or market reasons, reasons of competition or consolidation or any other reason, could have a material adverse impact on our financial condition, results of operations and cash flows, especially in a 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 a 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 public health threats, 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. 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 on certain of our owned rigs to cover
lost cash flow when a rig is damaged (other than when caused by named windstorms in the U.S. Gulf of Mexico), we have not purchased loss-of-hire insurance for our entire fleet. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks. In addition, our insurance may not cover losses associated with pandemics such as the COVID-19 pandemic or other global health threats.
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.
The Ocean GreatWhite reported an equipment incident on February 1, 2024 while located west of the Shetland Islands. The rig’s lower marine riser package, which we refer to as the LMRP, had been disconnected from the rig’s BOP on the well while waiting on harsh weather. Subsequently, the LMRP and the deployed riser string unintentionally separated from the rig, and the LMRP and riser dropped to the seabed. As of the date of this report, we are investigating the incident to understand the cause of the separation and we are evaluating the costs of recovery, repair and replacement of the damaged equipment, the expected duration of downtime associated with incident and any resulting loss of revenue. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Recent Event” in Item 7 of this report.
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 or hacker attacks, the introduction of malicious computer viruses, ransomware, utility outages, theft, design defects, insider risk, 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, could subject
us to significant liabilities and could have a material adverse effect on our operations, financial condition, business or reputation. Further, as cyber incidents continue to evolve, we may be required to incur additional costs to continue to modify or enhance our protective measures or to investigate or remediate the effects of cyber incidents.
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could adversely affect the market for offshore drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
We rely on third-party suppliers, manufacturers and service providers to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction.
Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes us to volatility in the quality, price and availability of such items. Certain components, parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well as an increase in operating costs and an increased risk of additional asset impairments.
Additionally, some of our suppliers, manufacturers and service providers have been negatively impacted by the industry downturn, global economic conditions (including inflation) and/or COVID-19 pandemic. If certain of our suppliers, manufacturers or service providers were to experience significant cash flow issues, become insolvent or otherwise curtail or discontinue their business as a result of such conditions, it could result in a reduction or interruption in supplies, equipment or services available to us and/or a significant increase in the price of such supplies, equipment and services.
Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.
Our contracts for our drilling rigs generally provide for the payment of an agreed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur on the project. Over the term of a drilling contract, our operating costs may fluctuate due to inflation or other events beyond our control. In addition, equipment repair and maintenance expenses vary depending on the type of activity the rig is performing, the age and condition of the equipment and general market factors impacting relevant parts, components and services. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers.
Inflation may adversely affect our operating results and increase working capital investments required to operate our business.
Inflationary factors such as increases in labor costs, material costs and overhead costs have adversely affected, and may continue to adversely affect, our operating results. Inflationary pressures may also increase other costs to operate, maintain or reactivate our drilling rigs. Our contracts for our drilling rigs generally provide for the payment of an agreed dayrate per rig operating day. Although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur on the project, we may not be able to fully recover increased costs due to inflation from our customers. If we are unable to recoup such increased costs, our operating margins will decline. Continuing or worsening inflation could significantly increase our operating expenses and capital expenditures, which could in turn have a material adverse effect on our business, financial condition, results of operations or cash flows.
The impact of public health threats, such as the COVID-19 pandemic, and efforts to mitigate the spread of such threats have adversely impacted, and could continue to adversely impact, our business, operations and financial results.
Beginning in March 2020, the COVID-19 pandemic and the actions taken by businesses and governments in response to it significantly slowed global economic activity and disrupted financial markets and international trade, resulting in a sharp decline in global oil demand and prices. These events had a material adverse effect on our business. Due to worldwide travel restrictions and mandatory quarantine measures designed to prevent or reduce the spread of COVID-19 in certain regions, we experienced increased difficulties, delays and costs in moving our personnel in and out of, and to work in, the various jurisdictions in which we operate. We also experienced permitting and regulatory delays, temporary shutdowns due to COVID-19 outbreaks on some of our drilling rigs and disruptions to or restrictions on the ability of our suppliers, manufacturers and service providers to supply parts, equipment or services in some of the jurisdictions in which we operate, whether as a result of government actions, labor shortages, the inability to source parts or equipment from affected locations, or other effects related to the COVID-19 outbreak. These events, or similar events in the future, could have significant adverse consequences on our ability to meet our commitments to customers, including by increasing our operating costs and increasing the risk of rig downtime and contract delays or terminations.
In May 2023, the World Health Organization declared an end to COVID-19 as a public health emergency, stressing that it does not mean that the disease is no longer a global threat. However, higher risk tolerance for individuals exists and travel and public contact in the regions in which we operate has increased to pre-pandemic levels. Most of the measures and restrictions initially implemented by us during 2020 have since been relaxed or lifted. Any resurgence in COVID-19 infections or new variants of the virus as well as additional public health threats could result in the imposition of new governmental lockdowns, quarantine requirements or other restrictions, impacting our ability to perform under our drilling contracts and, thus, negatively impacting our results of operations and financial condition.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility in how we manage our personnel.
Outside of the U.S., it is not unusual for us to be subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel costs and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes, work stoppages, or threats thereof, and other labor disruptions in certain countries where we operate. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.
Certain legal obligations in the countries in which we operate require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations in these countries could increase our costs and have a material adverse effect on our business, financial condition, results of operations or cash flows.
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. Additionally, many of our drilling contracts specify a minimum number of crew (or Minimum POB) required to be on board the rig at all times while the rig is under contract. Although our rigs can safely operate with staffing below the contracted Minimum POB, the drilling contracts often provide for us to incur a financial penalty for failure to maintain the Minimum POB.
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, disability or death, could have a material adverse effect on us.
As part of our business strategy, we may pursue business opportunities that include acquisitions of businesses or drilling rigs, mergers or joint ventures or other investments, and such transactions would present various risks and uncertainties.
We may pursue transactions that involve the acquisition of businesses or assets, mergers or joint ventures or other investments that we believe will enable us to further expand or enhance our business. Any such transaction would be evaluated on a case-by-case basis, and its consummation would depend upon numerous factors, including identifying suitable targets or assets that align with our business strategy, reaching agreement with the potential counterparties on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions. Any such transactions would involve various risks including, among others, the following:
•difficulties related to integrating or managing applicable parts of an acquired business or joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing;
•diversion of management’s attention from day-to-day operations;
•failure to realize anticipated benefits, such as cost savings, revenue enhancements or business synergies;
•the potential for substantial transaction expenses; and
•potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time any such transaction is consummated.
Financial and Tax Risks
Our financial performance after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.
Our capital structure was significantly impacted by the Plan. Upon our emergence from bankruptcy, we adopted fresh start accounting, which required that new fair values be established for the Company’s assets, liabilities, and equity as of the date of emergence from bankruptcy on April 23, 2021. The Effective Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor. Accordingly, because fresh start accounting rules apply, our financial condition and results of operations following emergence from the Chapter 11 Cases may not be comparable to the financial condition or results of operations reflected in our historical financial statements prior to our emergence from bankruptcy.
Our Senior Secured Second Lien Notes and revolving credit agreement contain various restrictive covenants, limiting the discretion of our management in operating certain aspects of our business.
Our debt instruments contain various restrictive covenants that may limit our management’s discretion in certain respects and contain negative covenants that limit the borrower's ability and the ability of its restricted subsidiaries to, among other things and subject to a number of important limitations and exceptions:
•incur, assume or guarantee additional indebtedness;
•create, incur or assume liens;
•make investments;
•sell or otherwise dispose of certain assets;
•enter into sale and leaseback transactions;
•pay dividends or distributions on capital stock or redeem or repurchase capital stock;
•enter into transactions with certain affiliates;
•prepay, redeem or amend certain indebtedness;
•sell stock of its subsidiaries; or
•enter into certain burdensome agreements.
Our failure to comply with these covenants could result in an event of default which, if not cured or waived, could result in all obligations under our debt instruments to be declared due and immediately payable, and all commitments under our revolving credit agreement to be terminated.
In addition, our revolving credit agreement obligates the borrower and its restricted subsidiaries to comply with certain financial maintenance covenants and, under certain conditions, to make mandatory prepayments and reduce the amount of credit available under the revolving credit agreement. Such mandatory prepayments and commitment reductions may affect cash available for use in our business.
See Note 10 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report.
Our variable rate indebtedness subjects us to interest rate risk that could have an adverse impact on us.
Borrowings under our revolving credit facility bear interest at variable rates, based on the applicable margin over market interest rates, and expose us to interest rate risk. Market interest rates increased significantly during 2022 and 2023, increasing the cost of debt service on our variable rate indebtedness. If market interest rates increase, our cost to borrow under our revolving credit facility 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 our revolving credit facility would effectively carry a fixed rate of interest, any hedging arrangement put in place may not offer complete protection from this risk.
The exercise of all or any number of the outstanding Emergence Warrants or the granting or vesting of stock-based awards will dilute the interests of the holders of our common stock.
On the Effective Date, our new organizational documents became effective authorizing the issuance of shares of common stock representing 100% of the equity interests in the Company as reorganized on the Effective Date in accordance with the Plan. Also on the Effective Date, and pursuant to the Plan, we entered into a warrant agreement which provided for the issuance of an aggregate of 7.5 million five-year warrants (or the Emergence Warrants). The Emergence Warrants have an exercise period of five years and are exercisable into 7% of the common stock representing 100% of the equity interests of the Company as reorganized on the Effective Date in accordance with the Plan, measured at the time of the exercise. The Emergence Warrants are initially exercisable for one share of our common stock per Emergence Warrant at an exercise price of $29.22 per Emergence Warrant.
Additionally, pursuant to the terms of the Plan, the Diamond Offshore Drilling, Inc. 2021 Long-Term Stock Incentive Plan (or the Equity Incentive Plan) was adopted and approved on the Effective Date. The Equity Incentive Plan provides for the grant of stock options, stock appreciation rights (or SARs), restricted stock, restricted stock units (or RSUs), performance awards, and other stock-based awards or any combination thereof to eligible participants.
The exercise of the Emergence Warrants or the granting or vesting of equity awards in the future will dilute the interests of the existing holders of our common stock and could have an adverse effect on the market for our common stock, including the price that an investor could obtain for such shares of our common stock.
We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.
In recent years, an oversupply of drilling rigs in the offshore drilling market has resulted in numerous rigs being idled and, in some cases, retired and/or scrapped. We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We have incurred impairment charges in the past, and may incur additional impairment charges in the future related to the carrying value of our drilling rigs. Impairment write-offs could result if, for example, any of our rigs become obsolete or commercially less desirable due to changes in technology, market demand or market expectations or their carrying values become excessive due to the condition of the rig, cold stacking the rig, the expectation of cold stacking the rig in the near future, a decision to retire or scrap the rig, or spending in excess of budget on a newbuild, construction project, reactivation or major rig upgrade. We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment, reflecting management’s assumptions and estimates regarding the appropriate risk-adjusted dayrate by rig, future industry conditions and operations and other factors. Asset impairment evaluations are, by their nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets, which could impact the need to record an impairment charge and the amount of any charge taken. From 2012 to the date of this report, we have retired and sold 39 drilling rigs and recorded impairment losses aggregating $2.9 billion. Historically, the longer a drilling rig remains cold stacked, the higher the cost of reactivation and, depending on the age, technological obsolescence and condition of the rig, the lower the likelihood that the rig will be reactivated at a future date. The current oversupply of rigs in our industry heightens the risk of future rig impairments. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates - Property, Plant and Equipment” in Item 7 of this report and Note 4 “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.
Environmental, Social and Governance Risks
Regulations relating to greenhouse gases and climate change could have a material adverse effect on our business.
Governments around the world are increasingly considering and adopting laws and regulations to address climate change issues. Lawmakers and regulators in the U.S. and other jurisdictions where we operate have focused increasingly on restricting the emission of carbon dioxide, methane and other “greenhouse” gases and have proposed or enacted regulations requiring reporting of greenhouse gas emissions and restricting such emissions, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy. For example, the SEC has proposed a mandatory climate change reporting framework that, if implemented, is likely to materially increase the amount of time, monitoring and reporting costs related to these matters. These and other new environmental regulations may unfavorably impact us, our suppliers and our customers.
In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be materially adversely affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our drilling rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations. Moreover, there is increased focus, including by governmental and non-governmental organizations, investors and other stakeholders on these and other sustainability matters. Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions.
In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have been enacted in some jurisdictions. Additionally, numerous large cities globally and several countries have adopted programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles, which may reduce demand for oil and natural gas and our drilling services. Such policies or other laws, regulations, treaties and international agreements related to greenhouse gases, climate change, carbon emissions or energy use may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons and thereby reduce demand for our drilling services, limit drilling in the offshore oil and natural gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which could materially adversely affect our business, operations, financial condition, operating results or cash flows.
Consumer preference and increasing demand for alternative fuels, energy sources and electric-powered vehicles may lead to reduced demand for contract drilling services.
The increasing penetration of renewable energy into the energy supply mix, and consumer preference and increasing demand for alternative fuels, energy sources and electric-powered vehicles may adversely impact the demand for oil and natural gas and, consequently, our contract drilling services. The evolving shift of the global energy system from fossil-based and other non-renewable energy sources to more renewable energy sources, commonly referred to as the energy transition, could have a material adverse impact on our results of operations, financial position and cash flows. As a result of changes in consumer preferences and uncertainty regarding the pace of the energy transition and expected impacts on oil and natural gas demand, some customers are transitioning their businesses to renewable energy projects and away from oil and natural gas exploration and production, which could result in reduced capital spending on oil and natural gas projects and in turn reduced demand for contract drilling services.
Increased focus on climate change, the environmental and social impacts of fossil fuel extraction and use, and other ESG matters could result in additional costs or risks and adversely impact our business and reputation and our access to capital and ability to refinance our debt.
Stakeholders, such as investors, customers, regulators and the lending community, have increased their focus on environmental, social and governance matters, including practices related to greenhouse gas emissions and climate change. Additionally, an increasing percentage of the investment community considers sustainability factors in making investment decisions, and an increasing number of entities are considering sustainability factors in awarding business. If we are unable to meet our commitments and targets and appropriately address sustainability enhancement, we may lose customers or business partners, and our reputation may be negatively affected. It may be more difficult for us to compete effectively, all of which could have a material adverse effect on our business, reputation, financial condition, results of operations, cash flows (including negative cash flows) and prospects.
Moreover, in recent years some leading asset managers have expressed a commitment to divest from investments in fossil fuels due to concerns over climate change, and some pension and endowment funds and other investors have begun to divest fossil fuel equities and pressure lenders to limit funding to companies engaged in the extraction of fossil fuels. 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.
Regulatory and Legal Risks
We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs.
Certain countries are subject to restrictions, sanctions and embargoes imposed by the U.S. government or other governmental or international authorities. These restrictions, sanctions and embargoes may prohibit or limit us from participating in certain business activities in those countries. Our operations are also subject to numerous local, state
and federal laws and regulations in the U.S. and in foreign jurisdictions concerning the containment and disposal of hazardous materials, the remediation of contaminated properties and the protection of the environment. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. Failure to comply with such laws and regulations could subject us to civil or criminal enforcement action, for which we may not receive contractual indemnification or have insurance coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected areas. We may be required to make significant expenditures for additional capital equipment or inspection and recertification thereof to comply with existing or new governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or result in a substantial reduction in revenues associated with downtime required to install such equipment or may otherwise significantly limit drilling activity.
In addition, these laws and regulations require us to perform certain regulatory inspections, which we refer to as a special survey. For most of our rigs, these special surveys are due every five years, although the inspection interval for our North Sea rigs is two-and-one-half years. Our operating income is negatively impacted during these special surveys. These special surveys are generally performed in a shipyard and require scheduled downtime, which can negatively impact operating revenue. Operating expenses may also increase as a result of these special surveys due to repair and maintenance costs that arise as a result of the inspection process. Repair and maintenance activities may also have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter. Operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between special surveys. Although an intermediate survey normally does not require shipyard time, the survey may require some downtime for the rig. We can provide no assurance as to the exact timing and/or duration of downtime and/or the costs or lost revenues associated with regulatory inspections, planned rig mobilizations and other shipyard projects.
In addition, the offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, can be affected by changes in tax and other laws relating to the energy business generally. In addition, the energy sector could be negatively impacted by executive orders and suspensions, as the administration focuses on the impact of climate change, targeting a fully clean energy economy and net-zero emissions by 2050.
Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could limit drilling opportunities.
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 48%, 53%, 41% and 55% of our total consolidated revenues for the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively, and include, or have included, operations in Senegal, Brazil, Australia, Myanmar and the U.K. Because we operate in various regions throughout the world, we are exposed to a variety of risks inherent in international operations, including risks of war or conflicts; political and economic instability and disruption; civil disturbance; acts of piracy, terrorism or other assaults on property or personnel; corruption; possible economic and legal sanctions (such as possible restrictions against countries that the U.S. government may consider to be state sponsors of terrorism); changes in global monetary and trade policies, laws and regulations; fluctuations in currency exchange rates; restrictions on currency exchange; controls over the repatriation of income or capital; and other risks. We may not have insurance coverage for these risks, or we may not be able to obtain adequate insurance coverage for such events at reasonable rates. Our operations may become restricted, disrupted or prohibited in any country in which any of these risks occur.
We are also subject to the following risks in connection with our international operations:
•kidnapping of personnel;
•seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of property or equipment;
•renegotiation or nullification of existing contracts;
•disputes and legal proceedings in international jurisdictions;
•changing social, political and economic conditions;
•imposition of wage and price controls, trade barriers, export controls or import-export quotas;
•difficulties in collecting accounts receivable and longer collection periods;
•fluctuations in currency exchange rates and restrictions on currency exchange;
•regulatory or financial requirements to comply with foreign bureaucratic actions;
•restriction or disruption of business activities;
•limitation of our access to markets for periods of time;
•travel limitations or operational problems caused by public health threats, including the COVID-19 pandemic, or changes in immigration policies;
•difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;
•difficulties in obtaining visas or work permits for our employees on a timely basis; and
•changing taxation policies and confiscatory or discriminatory taxation.
We are also subject to the regulations of the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations in addition to domestic and international anti-bribery laws and sanctions, trade laws and regulations, customs laws and regulations, and other restrictions imposed by other governmental or international authorities. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to us, among other things. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act 2010 or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions. In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling rigs; import-export quotas or other trade barriers; repatriation of foreign earnings or capital; oil and gas exploration and development;
local content requirements; taxation of offshore earnings and earnings of expatriate personnel; and use and compensation of local employees and suppliers by foreign contractors.
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
Not applicable.

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ITEM 2. PROPERTIES
Item 2. Properties.
We lease office space in Houston, Texas, where our corporate headquarters are located. Additionally, we lease various office, warehouse and storage facilities in Louisiana and internationally in Australia, Brazil, Malaysia, Senegal, Singapore and the U.K. to support our offshore drilling operations. We own offices and other facilities in New Iberia, Louisiana; Aberdeen, Scotland; Macae, Brazil; and Ciudad del Carmen, Mexico.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
See information with respect to legal proceedings in Note 11 “Commitments and Contingencies” to our Consolidated Financial Statements in Item 8 of this report.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.				
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information and Holders of Record
On the Effective Date, pursuant to the Plan, the Successor company issued an aggregate of approximately 100.0 million shares of common stock, par value $0.0001 per share, representing 100% of the equity interests in the reorganized company, and 7.5 million five-year warrants to purchase our common stock. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 of this report and Note 2 “Chapter 11 Proceedings - New Diamond Common Shares and New Warrants” to our Consolidated Financial Statements included in Item 8 of this report.
We received approval in the first quarter of 2022 to relist our unrestricted common stock on the New York Stock Exchange (or NYSE) under the ticker symbol “DO.” Our common stock commenced trading on the NYSE on March 30, 2022.
As of February 23, 2024, there were approximately 149 holders of record of our common stock. This number represents registered stockholders of record and does not include stockholders who hold their shares through an institution.
Dividend Policy
The Predecessor company had not paid a dividend to stockholders since 2015. For the Successor company, any future dividends will be at the discretion of our Board after taking into account various factors it deems relevant, including our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and contractual obligations. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. Our ability to declare cash dividends is generally prohibited under our debt covenants. See Note 10 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report.
Cumulative Total Stockholder Return
The following chart illustrates the cumulative total stockholder return for our common stock, the Standard & Poor’s SmallCap 600 Index and the Dow Jones U.S. Oil Equipment & Services Index, assuming $100 invested on March 30, 2022 in our common stock and the two published indices and reinvestment of dividends. The chart depicts the past performance for the period from March 30, 2022, the day our common stock commenced trading on the NYSE, through December 31, 2023, and should not be used to predict future share performance. The following chart and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended (or the Securities Act), or Exchange Act except to the extent that we specifically incorporate it by reference into such filing.
Mar. 30,
June 30,
Sep. 30,
Dec. 31,
Mar. 31,
June 30,
Sep. 30,
Dec. 31,
Diamond Offshore
$
S&P SmallCap 600 Index
$
Dow Jones U.S. Oil Equipment & Services
$

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved].

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with Item 1A, “Risk Factors” and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
This section of this Form 10-K generally discusses the Successor periods for the years ended December 31, 2023 and 2022. For a discussion of our financial condition and results of operations for the Successor periods for the year ended December 31, 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, 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, 2022 filed with the SEC on February 28, 2023.
We provide contract drilling services to the energy industry around the globe with a fleet of 13 offshore drilling rigs, consisting of four owned drillships, seven owned semisubmersible rigs and two managed rigs as of the date of this report.
Bankruptcy Filing
As discussed in Item 1 of this report, 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 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.
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 10 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria for and were required to adopt fresh start accounting in accordance with ASC 852, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date.
Fresh start accounting required 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 are not comparable with the financial statements prior to and including April 23, 2021. References to “Successor” refer to the Company and its financial position and results of operations after the Effective Date (or the years ended December 31, 2023 and 2022 and the period from April 24, 2021 to December 31, 2021). References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Effective Date (or from January 1, 2021 to April 23, 2021).
See Note 2 “Chapter 11 Proceedings” to our Consolidated Financial Statements included in Item 8 of this report.
Market Overview
During the fourth quarter of 2023, energy industry fundamentals continued to support the multi-year global growth cycle in our business. Despite some price volatility related to central bank rate hikes, macroeconomic uncertainty, non-OPEC supply growth, and renewed geopolitical unrest in the Middle East, commodity prices remained robust during the fourth quarter. According to pricing data published by the U.S. Energy Information Administration, Brent oil prices averaged approximately $84 per barrel in the fourth quarter. Many industry analysts expect Brent oil prices to average in the $80 per barrel range through 2026, this is well above most offshore project break-even prices, which, according to industry data, are below $50 per barrel. Against this backdrop of strong commodity prices, 2023 saw the highest level of sanctioned offshore capital spending since 2013 when the active deepwater fleet was more than twice the size it is today. Looking ahead, industry experts believe the oil and gas industry is poised for continued strong spending trends for the next several years, as multi-year energy demand expansion is expected. According to industry experts, offshore upstream spending is expected to average $215 billion annually from 2024 through 2026, growing at an average annual rate of approximately 5% while deepwater spending is anticipated to grow approximately 8% in 2024.
During the fourth quarter, the positive dynamics of increased offshore spending, coupled with the growing trend in long-cycle developments, capacity expansions, and exploration and appraisal activities, continued to drive growth in demand for floating drilling rigs. According to industry reports, on a trailing four-quarter basis, the volume of incoming floater tenders continued to grow throughout 2023, reaching a level in the fourth quarter not seen since 2012. In early February 2024, outstanding demand for deepwater rigs reached approximately 115 rig years, compared to 71 rig years in February 2023, representing an increase of more than 60% with most demand concentrated in the deepwater and ultra-deepwater regions of the Gulf of Mexico, Brazil and West Africa, which are areas where we currently operate. This increase in recent tendering activity continued to build visibility for floating rig demand. Analysts expect floating rig demand to grow approximately 11% in 2024 and average 7% annual growth through 2028, primarily driven by new greenfield developments and higher exploration activity. The increase in offshore exploration would present potential upside for future rig demand. This growing rig demand has resulted in increased contract durations and increased lead times from contract award to commencement of service for floater contracts signed so far in 2024, as operators become more willing to commit to rigs for longer periods for deepwater drilling capacity. According to industry analysts, as of the date of this report, duration and lead times for floating rig contracts signed in 2024 year to date were 2.40 years and 0.64 years, respectively, which is generally in line with levels seen in 2023.
Strong demand for deepwater drilling rigs has resulted in increasing rates and utilization for ultra-deepwater drilling rigs, with current dayrates in the mid-to-upper $400,000 per day range, and marketed utilization approaching 95%. This dayrate market, combined with the longer duration and lead times of recent tenders, has resulted in compelling economics for rig reactivations, presenting the opportunity for some idle capacity to enter the market, which could adversely affect future utilization and dayrates. While there is a possibility for stranded rigs to enter the market, the current remaining inventory of idle rig capacity has decreased significantly and the owners of this capacity have, to date, exhibited capital discipline as it relates to reactivations. The anticipated growth in upstream capital spending has continued to drive further increases in rig demand and may mitigate the long-term impact of future rig reactivations. Further, supply chain constraints and inflationary pressures could limit the pace at which these additional rigs can return to the market, with some analysts estimating the average time for rig reactivations to be approximately 12 to 18 months, with costs approaching $100 million for idle rigs and $350 million for stranded rigs. Despite policy tightening by major central banks and a moderating pace of world economic expansion, inflationary pressures have generally remained elevated in the industry sector, though recent trends indicate a moderation. This may still result in upward pressure on operating expenses for offshore drillers.
In addition to market factors, customer capital allocation decisions have continued to affect demand for our services. Customer investment mixes over time, coupled with energy demand and regulatory measures, could adversely impact demand for offshore drilling services in the long term. Notwithstanding this possibility, during the fourth quarter global energy demand continued to be strong and energy supply growth remained constrained. We expect increased investment in both traditional and renewable sources of energy to be required in the future, some of which we expect to be invested in finding and producing hydrocarbons in the offshore segment. Industry experts continue to expect the world's demand for energy will continue to rise and that hydrocarbons will play a major role in meeting the world's energy needs for the foreseeable future.
See “- Contract Drilling Backlog” for future commitments of our rigs during 2024 through 2028.
Recent Event
On February 1, 2024, the Ocean GreatWhite, reported an equipment incident while located in the North Sea west of the Shetland Islands. We had disconnected the rig’s lower marine riser package (or LMRP) from the rig’s BOP on the well while waiting on harsh weather. Subsequently, the LMRP and the deployed riser string unintentionally separated from the rig at the slip joint tensioner ring, and the LMRP and riser dropped to the seabed. As of the date of this report, we continue to investigate the incident to understand the cause of the separation and are working closely with our customer and local authorities in response to the incident. At the time of the incident, the rig was not carrying out any drilling activity. No employees were injured, the rig maintained its structural integrity and the well was secure with the BOP in place. In addition, as of the date of this report, there have been no reports of damage to seabed infrastructure and no known environmental impacts or lower hull damage.
We have initiated a process for recovering the LMRP, riser and replacing missing or damaged rig equipment. The Ocean GreatWhite is currently in process of recovering the LMRP to the surface. Since the incident, the rig has been off-rate and is not expected to return to earning dayrate until it is operating again, which we estimate could be approximately 90 to 100 days or longer. If the rig is off-rate for 90 to 100 days, it could result in approximately $24.0 million to $27.0 million in estimated reduced revenue over the course of the first and second quarters of 2024.
We carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico. As of the date of this report, we estimate incremental recovery and repairs and maintenance costs to be approximately $20.0 million to $25.0 million dollars, and our current estimate of replacement capital expenditures is approximately $12.0 million to $15.0 million dollars. We anticipate that the LMRP incident will be covered by our hull & machinery insurance policy and that all incremental costs, less our $10.0 million deductible, should be reimbursable under that policy. In addition, we carry loss-of-hire insurance on the Ocean GreatWhite to cover lost cash flow under certain circumstances. After a 60-day waiting period, our loss-of-hire insurance provides $150,000 per day, for up to 180 days, for each day of lost revenue as a result of a covered property loss claim. However, we cannot fully predict the extent of such insurance coverage or the timing of such claims.
Contract Drilling Backlog as of January 1, 2024, as presented below, includes $65.3 million of future revenue and 249 rig days committed in 2024 attributable to the Ocean GreatWhite and has not been adjusted to reflect any potential lost revenue or revenue-earning days resulting from the LMRP incident.
Contract Drilling Backlog
Contract drilling backlog, as presented below, includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue to be earned and the actual periods during which revenues will be earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including weather conditions and unscheduled downtime for repairs and maintenance. 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 “- Recent Event” and “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 3 “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 3 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 contracts.
The following table reflects our contract drilling backlog attributable to future operations as of January 1, 2024 (based on information available at that time), October 1, 2023 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023), and January 1, 2023 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2022) (in millions).
January 1,
October 1,
January 1,
Contract Drilling Backlog (1)
$
1,424
$
1,406
$
1,788
(1)Includes contract backlog of $117.6 million, $156.3 million and $307.7 million at January 1, 2024, October 1, 2023 and January 1, 2023, respectively, attributable to customer drilling contracts secured for rigs managed, but
not owned, by us. We entered into the drilling contracts directly with the customer and will receive and recognize revenue under the terms of the contract. Pursuant to the terms of the charter agreement with the rig owner, we will realize a gross margin equivalent to our management and marketing fee.
The following table reflects the amounts of our contract drilling backlog by year as of January 1, 2024 (in millions).
For the Year Ending December 31,
Total
Contract Drilling Backlog (1)
$
1,424
$
$
$
$
$
(1)Includes contract backlog of $117.6 million in 2024 attributable to customer drilling contracts secured for two rigs that we manage under the MMSA with an offshore drilling company whereby we provide management services for these rigs.
The following table reflects the percentage of rig days committed by year as of January 1, 2024. 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).
For the Year Ending December 31,
Rig Days Committed (1)
62%
19%
17%
16%
<1%
(1)As of January 1, 2024, includes approximately 135 rig days currently known and scheduled for contract preparation, mobilization of rigs, surveys and extended repair and maintenance projects during 2024.
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®.”
Regulatory Surveys and Expected 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 that are not related to the recertification of the vessel, are expensed as incurred. Costs for vessel improvements that 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 2024, we expect to spend approximately 135 days of planned downtime, including approximately (i) 90 days for a shipyard project for the Ocean BlackRhino; (ii) 20 days for the Ocean Hornet’s special survey; (iii) 15 days for the Ocean Endeavor’s BOP recertification; and (iv) 10 days for other planned rig moves. 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 results of operations, financial condition, 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 of our owned rigs to cover lost cash flow when a rig is damaged (other than when caused by named windstorms in the U.S. Gulf of Mexico).
In addition, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, collisions, and wreck removals, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Under these marine liability policies, we self-insure $1.0 million to $5.0 million per occurrence, depending on jurisdiction, but up to $25.0 million for liabilities arising out of named windstorms in the U.S. Gulf of Mexico. Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceeds certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence.
Impact of Changes in Tax Laws or Their Interpretation. We operate through our various subsidiaries in a number of jurisdictions throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments
and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
On August 16, 2022, the Inflation Reduction Act (or the IRA) was enacted by the United States. Among other provisions, the IRA includes a 15% corporate minimum tax rate applied to certain large corporations and a 1% excise tax on corporate stock repurchases made after December 31, 2022. We do not expect these provisions of the IRA to have a material impact on our operating results, financial condition, or cash flows.
In October 2021, approximately 140 countries in the OECD/G20 Inclusive Framework on Base Erosion and Profit Shifting reached an agreement on international tax reform, including rules to ensure that multinational groups of companies pay a minimum corporate income tax rate of 15% (or Pillar Two). The OECD continues to release additional guidance on how Pillar Two rules should be interpreted and applied by jurisdictions as they adopt Pillar Two. A number of countries have utilized the administrative guidance as a starting point for legislation that is effective January 1, 2024. We continue to evaluate the Pillar Two impact on future periods, pending legislative adoption by individual countries and issuance of additional guidance by tax authorities.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:
Property, Plant and Equipment. We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. During the Successor periods for the years ended December 31, 2023 and 2022, we capitalized $124.3 million and $69.1 million, respectively, in replacements and betterments of our drilling fleet.
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, a change in the economic useful life of a rig, cold stacking a rig, the expectation of cold stacking a rig in the near future, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project, reactivation or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
•dayrate by rig;
•utilization rate by rig if active, warm-stacked or cold-stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);
•the per day operating cost for each rig if active, warm-stacked or cold-stacked;
•the estimated annual cost for rig replacements and/or enhancement programs;
•the estimated maintenance, inspection or other reactivation costs associated with a rig returning to work;
•the remaining economic useful life of a rig;
•salvage value for each rig; and
•estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we assign a probability of occurrence. We arrive at a projected probability-weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment.
Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a sustained decline in oil and gas prices, cancellations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, capital expenditures required due to advances in offshore drilling technology, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different.
When an impairment is indicated, we have historically estimated the fair value of the impaired rig using an income approach, whereby the fair value of the rig is estimated based on a calculation of the rig’s future net cash flow (on a probability-weighted basis) over its remaining estimated economic useful life, using similar inputs and assumptions as described above, and discounted based on our weighted average cost of capital. These cash flow projections utilized significant unobservable inputs, including management’s assumptions related to estimated dayrate revenue, rig utilization and estimated capital expenditures, repair and regulatory survey costs, as well as estimated proceeds that may be received on ultimate disposition of the rig.
We did not record an impairment loss in 2023 or 2022. During the Successor period from April 24, 2021 through December 31, 2021, we reviewed the marketability, age and physical condition of certain of our rigs in conjunction with other factors specific to the geographic markets in which these rigs are capable of operating and determined, based on circumstances that arose in the fourth quarter of 2021, which we believed to be other than temporary, that the economic useful lives of certain of the rigs were materially different than that determined at the Effective Date. Based on the revised useful lives, we determined that the carrying values of two semisubmersible rigs were impaired. We recognized an aggregate impairment loss of $132.4 million to write down these rigs to their estimated fair value. During the Predecessor period from January 1, 2021 through April 23 2021, we recognized an impairment loss of $197.0 million for one rig for which we had concerns regarding future opportunities. See “- Results of Operations - Impairment of Assets” and Note 4 “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.
Results of Operations
Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning, or R-E, days, rig utilization and average daily revenue. The following table presents these three key performance indicators and other comparative data relating to our revenues and operating expenses (in thousands, except days, daily amounts and percentages).
Year Ended December 31,
Revenue-Earning Days (1)
3,293
3,089
Utilization (2)
%
%
Average daily revenue (3)
$
298,800
$
234,600
Revenues:
Contract drilling
$
983,983
$
724,744
Revenues related to reimbursable expenses
72,196
116,534
Total revenues
1,056,179
841,278
Operating expenses:
Contract drilling, excluding depreciation
757,193
620,982
Reimbursable expenses
68,758
114,962
Depreciation
111,301
103,478
General and administrative
72,248
70,196
Gain on disposition of assets
(4,382
)
(4,895
)
Total operating expenses
1,005,118
904,723
Operating income (loss)
51,061
(63,445
)
Other income (expense):
Interest income
1,637
Interest expense
(53,416
)
(40,423
)
Foreign currency transaction loss
(5,920
)
(3,023
)
Loss on extinguishment of long-term debt
(6,529
)
-
Other, net
(556
)
1,267
Loss before income tax (expense) benefit
(13,723
)
(105,606
)
Income tax (expense) benefit
(30,983
)
2,395
Net loss
$
(44,706
)
$
(103,211
)
(1)An R-E day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.
(2)Utilization is calculated as the ratio of total R-E days divided by the total calendar days in the period for all specified rigs in our fleet (including cold-stacked rigs).
(3)Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per R-E day.
Contract Drilling Revenue. Contract drilling revenue increased $259.2 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Comparing the periods, the increase in contract drilling revenue was the result of higher average daily revenue earned ($211.2 million), combined with a 204-day increase in R-E days ($48.0 million).
Average daily revenue for 2023 increased compared to 2022, primarily due to dayrates earned by the Ocean BlackHornet and West Auriga, which operated under new contracts or extensions during the majority of 2023 at higher dayrates than those earned during 2022. Contract drilling revenue for 2023 also included revenue for the Ocean GreatWhite and West Vela, which commenced drilling operations in the first quarter of 2023 and fourth quarter of 2022, respectively, and the Ocean BlackHawk operating in the GOM after completion of its contract in Senegal in
mid-2023 and shipyard upgrade. We also recognized $19.2 million in revenue related to the early termination of drilling contracts for the Ocean Patriot and the Ocean Apex in 2023.
R-E days for 2023 increased, compared to the prior year, due to incremental R-E days for the reactivated Ocean GreatWhite (275 days), our two managed rigs (283 days), which were on contract for the majority of 2023, the Ocean Endeavor (62 days), which completed a shipyard project in the first quarter of 2023 and other net changes (2 days). R-E days in 2023 were partially reduced as a result of the completion of contracts the Ocean Onyx and Ocean Monarch (274 fewer days) and subsequent cold stacking, and downtime associated with shipyard projects and contract preparation activities for the Ocean Courage and the Ocean BlackHawk (144 fewer days).
Revenue Related to Reimbursable Expenses. Gross reimbursable revenue and expenses for the years ended December 31, 2023 and 2022 were $72.2 million and $116.5 million, respectively, and included $8.5 million and $61.2 million, respectively, of revenue earned for the rigs managed under the MMSA.
Contract Drilling Expense, Excluding Depreciation. Contract drilling expense, excluding depreciation increased $136.2 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. During 2023, contract drilling expense associated with the two managed rigs, including bareboat charters thereof, increased $139.9 million compared to 2022, primarily due to both the West Auriga and West Vela being on contract for most of 2023 compared to the prior year. Contract drilling expense for our owned fleet decreased $3.7 million in 2023, compared to 2022, and reflected lower costs for repair, inspection and maintenance-related activities ($11.5 million) and personnel ($10.7 million), partially offset by higher costs for rig mobilization ($11.4 million), equipment rental ($4.8 million) and other expenses ($2.3 million). The net decrease in contract drilling expense for our owned rigs was due to a reduction in costs in 2023 attributed to the cold-stacked Ocean Onyx and Ocean Monarch, partially offset by costs related to the operation of the reactivated Ocean GreatWhite, a shipyard upgrade for the Ocean Apex and higher expenses related to our operations in Senegal.
Depreciation Expense. Depreciation expense for 2023 increased $7.8 million compared to 2022. The net increase in depreciation expense was primarily due to a higher depreciable asset base in 2023 as a result of capital expenditures during the year, including shipyard projects for the Ocean Apex, Ocean BlackHawk and Ocean Courage.
General and Administrative Expense. General and administrative expense increased $2.1 million for the year ended December 31, 2023, compared to year ended December 31, 2022, primarily due to higher personnel-related costs ($6.6 million), legal and other professional fees ($0.7 million) and other expenses ($0.2 million), partially offset by a reduction in stock compensation expense due to the absence of expense associated with the vesting of certain performance-based restricted stock awards in 2022 ($5.4 million).
Gain on Disposition of Assets. During 2023, we recognized an aggregate gain on disposition of assets of $4.3 million, primarily related to the sale of surplus equipment. During 2022, we sold the Ocean Valor for aggregate proceeds of approximately $6.6 million and recognized a net gain on the transaction of $4.0 million.
Interest Expense. Interest expense increased $13.0 million for the year ended December 31, 2023 compared to the year ended December 31, 2022, and included $13.4 million in interest expense related to our $550.0 million aggregate principal amount of senior secured second lien notes, including amortization of debt issuance costs, and higher interest expense related to amounts drawn on our revolving credit facility prior to its repayment in September 2023 ($3.3 million). The increase in interest expense for 2023 was partially offset by a reduction in interest expense year-over-year related to the retirement of certain indebtedness we incurred upon emergence from bankruptcy ($2.4 million), our finance leases ($1.1 million), and other interest ($0.2 million).
Loss on Extinguishment of Long-Term Debt. Concurrent with our issuance of $550.0 million aggregate principal amount of senior secured second lien notes in September 2023, we retired all our previously outstanding debt and amended our revolving credit facility to reduce the borrowing capacity thereunder. We recognized a $6.5 million loss on extinguishment of debt, primarily related to the retirement of a portion of our then existing debt at a premium ($3.4 million) and the write off of deferred issuance costs related to the retired debt and reduction in borrowing capacity under our revolving credit facility ($3.1 million).
Income Tax (Expense) Benefit. We recorded an income tax expense of $31.0 million (effective tax rate of negative 225.77%) for the Successor year ended December 31, 2023, inclusive of a net $12 million additional tax expense with
respect to prior years’ operations in Egypt upon final judgment by the Egyptian tax court and income tax benefit of $2.4 million (2.27% effective tax rate) for the Successor year ended December 31, 2022.
The effective tax rate of negative 225.77% for the Successor year ended December 31, 2023 reflected changes in the domestic and international jurisdictional mix of our pre-tax income and loss, the utilization of deferred tax assets, and the recognition of additional uncertain tax positions in foreign jurisdictions.
The effective tax rate of 2.27% for the Successor year ended December 31, 2022 reflected changes in the domestic and international jurisdictional mix of our pre-tax income and loss and the release of previously recognized valuation allowances.
Liquidity and Capital Resources
In September 2023, we issued $550.0 million aggregate principal amount of 8.5% senior secured second lien notes due 2030 (or the Second Lien Notes), which are scheduled to mature on October 1, 2030 (or the Notes Offering). Concurrent with the issuance of the Second Lien Notes, we entered into an amendment (or the Credit Agreement Amendment) to our then-existing $400.0 million exit revolving credit agreement (or the Exit RCF) which amended the Exit RCF (or, as amended, the Amended RCF) to, among other things, (i) reduce the aggregate commitment of the lenders thereunder from $400.0 million to $300.0 million, (ii) permit the Notes Offering and (iii) permit us to incur up to an aggregate of $50.0 million of indebtedness in respect of outstanding letters of credit that may be issued on our behalf outside of the Amended RCF. The Credit Agreement Amendment became effective concurrently with the consummation of the Notes Offering, which was conditioned on the Credit Agreement Amendment becoming effective.
We used a portion of the net proceeds from the Notes Offering to fully repay and terminate our $100.0 million senior secured exit term loan credit facility (or the Exit Term Loan Credit Facility), redeem in full our 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (or First Lien Notes) and repay all amounts outstanding under the Exit RCF. We intend to use the remaining net proceeds for general corporate purposes.
See Note 10 “Long-Term Debt” to our Consolidated Financial Statements included in Item 8 of this report.
On October 24, 2023, Barclays Bank PLC (or Barclays) gave notice of its resignation as a letter of credit issuer under the Amended RCF. Barclays’ resignation became effective on November 23, 2023 and as a result our capacity for the issuance of additional letters of credit under the Amended RCF was reduced to zero at that time. However, the Amended RCF permits us to incur up to an aggregate of $50.0 million of indebtedness in respect of outstanding letters of credit that may be issued on our behalf outside of the Amended RCF.
At February 23, 2024, we had no borrowings outstanding under the Amended RCF, and a $1.9 million letter of credit had been issued thereunder. As of February 23, 2024, approximately $298.1 million was available for borrowings under the Amended RCF subject to its terms and conditions; however, the availability of borrowings under the Amended RCF is subject to the satisfaction of certain conditions as specified in our revolving credit agreement, including restrictions on borrowings. The Amended RCF permits us to incur up to an aggregate of $50.0 million of indebtedness in respect outstanding letters of credit that may be issued on our behalf outside of the Amended RCF.
Historically, we have relied on our cash flows from operations and cash reserves to meet our liquidity needs, which primarily include funding our working capital requirements and capital expenditures, as well as servicing our debt repayments and interest payments. As of February 23, 2024, all of our rigs, excluding managed rigs, are owned and operated, directly or indirectly, by Diamond Foreign Asset Company (or DFAC). Our management has determined that we will permanently reinvest foreign earnings, which restricts the ability to utilize cash flows of DFAC on a company-wide basis. To the extent possible, we expect to utilize the operating cash flows and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each respective entity's working capital requirements and capital commitments.
From time to time, based on market conditions and other factors, we may seek to repay, refinance or restructure all or a portion of our outstanding indebtedness or otherwise enter into transactions regarding our capital structure to obtain more favorable terms, enhance flexibility in conducting our business, increase liquidity or otherwise. We regularly evaluate capital markets to consider future opportunities for enhancements of our capital structure and may opportunistically pursue financing transactions to optimize our capital structure. Our ability to access the capital
markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control, and there can be no assurance that we would be able to complete any such offering of securities.
As of January 1, 2024, our contractual backlog was approximately $1.4 billion. At December 31, 2023, we had cash and cash equivalents of $138.7 million, including $14.2 million that is subject to restrictions pursuant to the MMSA.
Sources and Uses of Cash
Cash Flows and Capital Expenditures
For the year ended December 31, 2023, our operating activities generated cash flow of $11.8 million compared to cash flow of $8.9 million for the year ended December 31, 2022.
2023. During 2023, cash receipts from contract drilling services ($971.2 million) were partially offset by cash expenditures for contract drilling, shorebase support, and general and administrative costs ($942.6 million), the placement of cash collateral in support of tax bonds ($11.8 million) and the payment of cash income taxes ($5.0 million).
Cash outlays for capital expenditures during 2023 aggregated $131.4 million, primarily related to shipyard projects and equipment upgrades for several rigs in our fleet, partially offset by proceeds from the disposition of assets ($11.1 million), including the sale of surplus equipment.
Additionally, during 2023, we issued $550.0 million aggregate principal amount of Second Lien Notes at par and used a portion of the proceeds to repay amounts outstanding under the Exit RCF, repay and terminate our Exit Term Loan Credit Facility and redeem in full the First Lien Notes ($381.2 million). Costs associated with the issuance of the Second Lien Notes and amendment of the Exit RCF were $17.0 million. Net borrowings under the Exit RCF prior to the Notes Offering were $15.0 million. During 2023, we also made payments in connection with finance lease obligations aggregating $17.0 million related to Well Control Equipment (as defined below) on our owned drillships.
2022. During 2022, cash receipts for contract drilling services ($781.0 million) and the return of certain collateral deposits ($17.5 million) were partially offset by cash expenditures for contract drilling, shorebase support and general and administrative expenses ($776.3 million) and payment of cash income taxes ($13.3 million).
In addition, our cash capital expenditures were $60.0 million, and we received $7.6 million from the sale of assets during 2022, including a deposit received for the sale of surplus equipment and proceeds from the sale of the Ocean Valor. Principal payments on our Well Control Equipment finance leases were $15.9 million. During the year ended December 31, 2022, we borrowed $94.0 million under the Exit RCF.
Upgrades and Other Capital Expenditures
We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet and our ongoing rig equipment replacement and capital maintenance programs. The amount of cash required to meet our capital commitments is determined by evaluating the need to upgrade our rigs to meet specific customer requirements and our rig equipment enhancement, maintenance and replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and our cash flow forecast. As of the date of this report, we expect cash capital expenditures for 2024 to be approximately $125.0 million to 135.0 million and excludes cash capital expenditures that may not be covered by insurance for the Ocean GreatWhite LMRP incident.
Contractual Cash Obligations
The following table sets forth our contractual cash obligations at December 31, 2023 (in thousands).
Payments Due By Period
Contractual Obligations (1)
Total
2025-2026
2027-2028
Thereafter
Second Lien Notes
$
878,548
$
51,944
$
93,500
$
93,500
$
639,604
Well Control Equipment services agreement (2)
92,492
24,862
67,631
-
-
Finance leases (3)
149,062
26,352
122,710
-
-
Operating leases (3)
46,350
11,181
19,044
13,337
2,788
Total obligations
$
1,166,452
$
114,339
$
302,885
$
106,837
$
642,392
(1)The above table excludes $48.6 million of total net unrecognized tax benefits related to uncertain tax positions that could result in a future cash payment as of December 31, 2023. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.
(2)Contractual obligations related to our Well Control Equipment services agreement include a commitment to purchase consumable and capital spare parts owned and controlled by the vendor at the end of the service arrangement for a purchase price based on current list prices not to exceed $37.0 million. The table above assumes that such items are purchased at the ceiling price at the end of the agreement in 2026, however, the actual amount may vary as the volume and prices of spares to be purchased are not yet known. See “- Pressure Control by the Hour®.”
(3)These contractual obligations are related to finance leases for our Well Control Equipment and include payments related to the exercise of a purchase option for the Well Control Equipment at the end of the original lease term. We have also entered into various operating leases for corporate and shorebase offices, office and information technology equipment, employee housing, onshore storage yards and certain rig equipment and tools. See Note 12 “Leases and Lease Commitments” to our Consolidated Financial Statements in Item 8 of this report.
Pressure Control by the Hour®. In 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly known as Baker Hughes, a GE company) (or Baker Hughes) to provide services with respect to certain blowout preventer and related well control equipment (or Well Control Equipment) on our four drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the contractual services agreement, we sold the Well Control Equipment on our drillships to a Baker Hughes subsidiary and are leasing it back over separate finance leases. Collectively, we refer to the contractual services agreement and corresponding finance lease agreements with the Baker Hughes affiliate as the PCbtH program. See Note 11 “Commitments and Contingencies” and Note 12 “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, 2023, except for those related to our direct rig operations, which arise during the normal course of business.
Other Commercial Commitments
We were contingently liable as of December 31, 2023 in the amount of $12.4 million under certain tax and customs bonds that have been issued on our behalf. The letter of credit that collateralizes the $1.9 million surety bond associated with our office lease was issued under the Amended RCF and cannot require collateral except in events of default. In addition, we have placed $11.8 million in cash collateral with the issuer of certain tax bonds.
The table below provides a list of these obligations in U.S. dollar equivalents by year of expiration (in thousands).
For the Year Ending December 31,
Other Commercial Commitments
Total
Tax bonds
$
12,381
$
-
$
9,239
$
-
$
-
$
3,142
Customs bonds
-
-
-
-
Office lease letter of credit
1,878
1,878
-
-
-
-
Total obligations
$
14,419
$
2,038
$
9,239
$
-
$
-
$
3,142
Other
Operations Outside the U.S. Our operations outside the U.S. accounted for approximately 48% and 53% of our total consolidated revenues for the Successor periods for the years ended December 31, 2023 and 2022, 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, Senegal, Trinidad and Tobago and the U.K., creating exposure to certain monetary assets and liabilities denominated in currencies other than the U.S. dollar. These assets and liabilities are revalued based on currency exchange rates at the end of the reporting period.
To reduce our currency exchange risk, we may, if possible, arrange for a portion of our international contracts to be payable to us in local currency in amounts equal to our estimated operating costs payable in local currency, with the balance of the contract payable in U.S. dollars. The revaluation of liabilities denominated in currencies other than the U.S. dollar related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, is reported as a component of “Income tax (expense) benefit” in our Consolidated Statements of Operations.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:
•market conditions and the effect of such conditions on our future results of operations;
•offshore exploration activity, future investment in hydrocarbons, future spending trends or growth, customer capital allocation and commitments, drilling contract duration trends, and customer spending programs and future projects;
•contractual obligations and future contract negotiations;
•future commodity prices, dayrates or utilization;
•market outlook;
•the transition to renewable energy sources and other alternative forms of energy;
•future energy demand and future demand for offshore drilling services;
•global energy demand and the role of hydrocarbons in meeting the world’s energy needs;
•inflation;
•future economic trends, including interest rates and recessionary economic conditions;
•operations outside the United States;
•geopolitical events and risks, including Russia’s invasion of Ukraine and related sanctions, conflict in the Middle East including the armed conflict between Israel and Hamas, and related disruptions;
•business strategy;
•strategic initiatives;
•growth opportunities;
•competitive position including, without limitation, competitive rigs entering the market;
•expected financial position and liquidity;
•cash flows and contract backlog;
•sources and uses of and requirements for financial resources and sources of liquidity;
•idling drilling rigs or reactivating stacked or stranded rigs;
•outcomes of litigation and legal proceedings;
•declaration and payment of dividends;
•expectations regarding our plans and strategies;
•financing plans;
•any repayment, refinancing or restructuring of our outstanding indebtedness or other transaction regarding our capital structure or any offering of securities or other capital markets transaction;
•debt levels and the impact of changes in the credit markets, including interest rates;
•budgets for capital and other expenditures;
•interest rate and foreign exchange risk;
•business plans or financial condition of our customers;
•duration and impacts of the COVID-19 pandemic, including new variants of the virus, lockdowns, re-openings and any other related actions taken by businesses and governments on the offshore drilling industry and our business, operations, supply chain and personnel, financial condition, results of operations, cash flows and liquidity;
•ESG trends, practices and related matters;
•tax planning and effects of the IRA;
•changes in tax laws and policies or adverse outcomes resulting from examination of our tax returns;
•contractual obligations related to our Well Control Equipment services agreement and potential exercise of the purchase option at the end of the original lease term;
•the MMSA and charters with an offshore drilling company and future management services thereunder;
•any response to the equipment incident on the Ocean GreatWhite, any related damage or environmental impact or efforts to recover equipment or replace any missing or damaged equipment;
•timing and duration of required regulatory inspections for our drilling rigs and other planned downtime;
•process and timing for acquiring regulatory permits and approvals for our drilling operations;
•timing and cost of completion of capital projects;
•delivery dates and drilling contracts related to capital projects;
•plans and objectives of management;
•sale or scrapping of retired rigs;
•asset impairments and impairment evaluations;
•assets held for sale;
•our internal controls and internal control over financial reporting;
•performance of contracts;
•cybersecurity;
•unionization efforts;
•compliance with applicable laws; and
•availability, limits and adequacy of insurance or indemnification.
These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:
•those described under “Risk Factors” in Item 1A;
•general economic and business conditions and trends, including recessions, inflation, and adverse changes in the level of international trade activity;
•the protracted downturn in our industry and the continuing effects thereof;
•worldwide supply and demand for oil and natural gas;
•changes in foreign and domestic oil and gas exploration, development and production activity;
•oil and natural gas price fluctuations and related market expectations;
•the ability of OPEC+ to set and maintain production levels and pricing, and the level of production in non-OPEC+ countries;
•policies of various governments regarding exploration and development of oil and gas reserves;
•inability to obtain contracts for our rigs that do not have contracts;
•inability to reactivate cold-stacked rigs;
•cancellation or renegotiation of contracts included in our reported contract backlog;
•advances in exploration and development technology;
•the worldwide political and military environment, including, for example, in oil-producing regions and locations where our rigs are operating or are in shipyards;
•casualty losses;
•operating hazards inherent in drilling for oil and gas offshore;
•the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;
•industry fleet capacity;
•market conditions in the offshore contract drilling industry, including, without limitation, dayrates and utilization levels;
•competition;
•changes in foreign, political, social and economic conditions;
•risks of international operations, compliance with foreign laws and taxation policies and seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of equipment and assets;
•risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;
•risks that our assumptions and analyses in the Plan are incorrect;
•the potential adverse effects of the Chapter 11 Cases on our liquidity, results of operations, access to capital resources or business prospects;
•the impact of the COVID-19 pandemic, including new variants of the virus, or future epidemics or pandemics on our business, including the potential for worker absenteeism, facility closures, work slowdowns or stoppages, supply chain disruptions, additional costs and liabilities, delays, our ability to recover costs under contracts, insurance challenges, and potential impacts on access to capital, markets and the fair value of our assets;
•customer or supplier bankruptcy, liquidation or other financial difficulties;
•the ability of customers and suppliers to meet their obligations to us and our subsidiaries;
•collection of receivables;
•foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;
•risks of war, military operations, other armed hostilities, sabotage, piracy, cyber-attack, terrorist acts and embargoes, including the armed conflicts between Russia and Ukraine and between Israel and
Hamas;;
•changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;
•reallocation of drilling budgets away from offshore drilling in favor of other priorities such as renewable energy or land-based projects;
•regulatory initiatives and compliance with governmental regulations including, without limitation, regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use;
•compliance with and liability under environmental laws and regulations;
•uncertainties surrounding deepwater permitting and exploration and development activities;
•potential changes in accounting policies by the FASB, SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance;
•development and increasing adoption of alternative fuels and energy sources;
•customer preferences;
•risks of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts;
•cost, availability, limits and adequacy of insurance;
•invalidity of assumptions used in the design of our controls and procedures and the risk that material weaknesses may arise in the future;
•business opportunities that may be presented to and pursued or rejected by us;
•the results of financing efforts;
•adequacy and availability of our sources of liquidity;
•risks resulting from our indebtedness;
•public health threats;
•negative publicity; and
•impairments of assets.
The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we refer to reports of third parties that purport to describe trends or developments in energy production or drilling and exploration activity. While we believe that each of these reports is reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.
New Accounting Pronouncements
For a discussion of recent accounting pronouncements that have had or are expected to have an effect on our Consolidated Financial Statements, see Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” in Item 7 of this report.
Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2023 and 2022, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ.
Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.
Interest Rate Risk. We have exposure to interest rate risk on our debt instruments arising from changes in the level or volatility of interest rates. As of December 31, 2023, we had no variable interest rate debt outstanding. Our Second Lien Notes have been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. As of December 31, 2022, our variable interest rate debt included $177.5 million of outstanding borrowings under the Exit RCF, $19.4 million for the issuance of letters of credit under the Exit RCF and our $100.0 million Exit Term Loan Credit Facility. At this level of variable rate debt, the impact of a 100-basis point increase in market interest rates would not have a material effect (estimated $3.0 million increase in interest expense on an annualized basis). Our First Lien Notes were issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts.
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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Diamond Offshore Drilling, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income or loss, stockholders’ equity, and cash flows, for each of the two years in the periods ended December 31, 2023 and December 31, 2022, and for the period from April 24, 2021 to December 31, 2021 (Successor Company operations), and for the period from January 1, 2021 to April 23, 2021 (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, 2023 and 2022, and the results of its operations and its cash flows for the years ended December 31, 2023 and 2022, and for the period from April 24, 2021 to December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements present fairly, in all material respects, the results of its operations and its cash flows for the period from January 1, 2021 to April 23, 2021, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2024, expressed an unqualified opinion on the Company's internal control over financial reporting.
Fresh Start Reporting
As discussed in Note 2 to the financial statements, on April 8, 2021, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective after the close of business on April 23, 2021. Accordingly, the accompanying financial statements have been prepared in conformity with FASB Accounting Standard Codification 852, Reorganizations, for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note 2 to the financial statements.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Income Taxes - Refer to Notes 1 and 13 to the financial statements
Critical Audit Matter Description
The Company accounts for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in the financial statements or tax returns. In each of the tax jurisdictions, the Company recognized a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards.
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.
Due to the multiple jurisdictions in which the Company files tax returns and the complexity of the tax laws and regulations, we identified the transfer pricing component of accounting for income taxes as a critical audit matter, since auditing management’s estimates of income taxes in foreign jurisdictions based on the application of transfer pricing methodologies required a high degree of auditor judgment and an increased extent of effort, including the use of our tax specialists and audit teams in the local jurisdiction knowledgeable of the tax laws of the applicable country.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Company’s application of transfer pricing methodologies, included the following, among others:
•We evaluated the appropriateness and consistency of management’s methods and assumptions used in the application of its transfer pricing methodology, which included testing the effectiveness of the related internal controls.
•With the assistance of our transfer pricing specialists, we evaluated the reasonableness of transfer pricing methodologies utilized by the Company.
•We tested the accuracy of transfer prices by recalculating the prices in accordance with the chosen methodology.
•With the assistance of our income tax specialists and audit teams in the local jurisdiction knowledgeable of the tax laws of the applicable country, we evaluated management’s assertions with respect to the Company’s entitlement to the economic benefits associated with the tax positions resulting from the application of transfer pricing methodology.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2024
We have served as the Company’s auditor since 1989.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Diamond Offshore Drilling, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 28, 2024, expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2024
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
December 31,
ASSETS
Current assets:
Cash and cash equivalents
$
124,457
$
63,041
Restricted cash
14,231
34,293
Accounts receivable
260,124
177,675
Less: allowance for credit losses
(5,801
)
(5,622
)
Accounts receivable, net
254,323
172,053
Prepaid expenses and other current assets
63,412
48,695
Asset held for sale
1,000
-
Total current assets
457,423
318,082
Drilling and other property and equipment, net of accumulated depreciation
1,156,368
1,141,908
Other assets
98,762
67,966
Total assets
$
1,712,553
$
1,527,956
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
$
42,037
$
47,647
Accrued liabilities
203,336
166,785
Taxes payable
34,817
30,264
Current finance lease liabilities
15,960
16,965
Total current liabilities
296,150
261,661
Long-term debt
533,514
360,644
Noncurrent finance lease liabilities
113,201
131,393
Deferred tax liability
10,966
Other liabilities
113,871
93,888
Commitments and contingencies (Note 11)
Total liabilities
1,067,702
848,286
Stockholders’ equity:
Preferred stock (par value $0.0001, 50,000 shares authorized, none issued and outstanding)
-
-
Common stock (par value $0.0001, 750,000 shares authorized; 103,189 shares issued and 102,322 shares outstanding at December 31, 2023; 101,884 shares issued and 101,320 shares outstanding at December 31, 2022)
Additional paid-in capital
978,575
964,467
Treasury stock
(8,493
)
(4,252
)
Accumulated deficit
(325,261
)
(280,555
)
Accumulated other comprehensive income
-
Total stockholders’ equity
644,851
679,670
Total liabilities and stockholders’ equity
$
1,712,553
$
1,527,956
The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Successor
Predecessor
Year Ended
Period from
Period from
December 31,
April 24, 2021 through
January 1, 2021 through
December 31, 2021
April 23, 2021
Revenues:
Contract drilling
$
983,983
$
724,744
$
465,328
$
153,364
Revenues related to reimbursable expenses
72,196
116,534
90,738
16,015
Total revenues
1,056,179
841,278
556,066
169,379
Operating expenses:
Contract drilling, excluding depreciation
757,193
620,982
364,539
181,626
Reimbursable expenses
68,758
114,962
89,284
15,477
Depreciation
111,301
103,478
68,504
92,758
General and administrative
72,248
70,196
53,494
15,036
Impairment of assets
-
-
132,449
197,027
Gain on disposition of assets
(4,382
)
(4,895
)
(1,024
)
(5,486
)
Total operating expenses
1,005,118
904,723
707,246
496,438
Operating income (loss)
51,061
(63,445
)
(151,180
)
(327,059
)
Other income (expense):
Interest income
1,637
Interest expense (excludes $35,390 of contractual interest expense on debt subject to compromise for the period from January 1, 2021 through April 23, 2021.)
(53,416
)
(40,423
)
(26,180
)
(34,827
)
Foreign currency transaction loss
(5,920
)
(3,023
)
(997
)
(172
)
Loss on extinguishment of long-term debt
(6,529
)
-
-
-
Reorganization items, net
-
-
(8,088
)
(1,639,763
)
Other, net
(556
)
1,267
10,752
Loss before income tax (expense) benefit
(13,723
)
(105,606
)
(175,690
)
(2,001,393
)
Income tax (expense) benefit
(30,983
)
2,395
(1,654
)
39,404
Net loss
$
(44,706
)
$
(103,211
)
$
(177,344
)
$
(1,961,989
)
Loss per share, Basic and Diluted
$
(0.44
)
$
(1.03
)
$
(1.77
)
$
(14.21
)
Weighted-average shares outstanding, Basic and Diluted
101,842
100,561
100,071
138,054
The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME OR LOSS
(In thousands)
Successor
Predecessor
Year Ended
Period from
Period from
December 31,
April 24, 2021 through
January 1, 2021 through
December 31, 2021
April 23, 2021
Net loss
$
(44,706
)
$
(103,211
)
$
(177,344
)
$
(1,961,989
)
Other comprehensive income, net of tax:
Unrealized gain on marketable securities (net of tax of $1)
-
-
-
Comprehensive loss
$
(44,686
)
$
(103,211
)
$
(177,344
)
$
(1,961,989
)
The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
Retained
Accumulated
Additional
Earnings
Other
Total
Common Stock
Paid-In
(Accumulated
Comprehensive
Treasury Stock
Stockholders’
Shares
Amount
Capital
Deficit)
Income
Shares
Amount
Equity
January 1, 2021 (Predecessor)
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
934,800
-
-
-
-
934,810
April 24, 2021 (Successor)
100,000
$
$
934,800
$
-
$
-
-
$
-
$
934,810
Net loss
-
-
-
(177,344
)
-
-
-
(177,344
)
Stock-based compensation, net of tax
-
10,239
-
-
-
-
10,239
December 31, 2021
100,075
$
$
945,039
$
(177,344
)
$
-
-
$
-
$
767,705
Net loss
-
-
-
(103,211
)
-
-
-
(103,211
)
Stock-based compensation, net of tax
1,245
-
19,428
-
(4,252
)
15,176
December 31, 2022
101,320
$
$
964,467
$
(280,555
)
$
-
$
(4,252
)
$
679,670
Net loss
-
-
-
(44,706
)
-
(44,706
)
Stock-based compensation, net of tax
1,002
-
14,108
-
-
(4,241
)
9,867
Unrealized gain on marketable securities
-
-
-
-
-
-
December 31, 2023 (Successor)
102,322
$
$
978,575
$
(325,261
)
$
$
(8,493
)
$
644,851
The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Successor
Predecessor
Year Ended
Period from
Period from
December 31,
April 24, 2021 through
January 1, 2021 through
December 31, 2021
April 23, 2021
Operating activities:
Net loss
$
(44,706
)
$
(103,211
)
$
(177,344
)
$
(1,961,989
)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation
111,301
103,478
68,504
92,758
Loss on impairment of assets
-
-
132,449
197,027
Reorganization items, net
-
-
-
1,587,392
Gain on disposition of assets
(4,382
)
(4,895
)
(1,024
)
(5,486
)
Loss on extinguishment of long-term debt
6,529
-
-
-
Deferred tax provision
(4,617
)
(3,482
)
(35,894
)
Stock-based compensation expense
14,103
20,159
10,766
-
Contract liabilities, net
4,580
(36,292
)
48,293
10,617
Contract assets, net
(2,434
)
1,694
(1,418
)
(742
)
Deferred contract costs, net
(12,099
)
(1,594
)
(13,081
)
(12,034
)
Long-term employee remuneration programs
-
-
Collateral deposits
(11,857
)
17,479
6,030
-
Other assets, noncurrent
1,254
(2,950
)
2,685
Other liabilities, noncurrent
(709
)
(2,092
)
(371
)
Other
2,900
2,256
1,579
2,683
Changes in operating assets and liabilities:
Accounts receivable
(88,714
)
(25,718
)
(16,984
)
2,108
Prepaid expenses and other current assets
(3,887
)
2,028
(2,791
)
Accounts payable and accrued liabilities
21,369
55,006
(40,133
)
29,302
Taxes payable
23,149
(19,170
)
6,056
(5,804
)
Net cash provided by (used in) operating activities
11,780
8,864
18,904
(100,064
)
Investing activities:
Capital expenditures
(131,449
)
(60,023
)
(42,812
)
(49,119
)
Proceeds from disposition of assets, net of disposal costs
11,105
5,959
1,053
7,484
Deposits on asset sales
1,670
-
-
Net cash used in investing activities
(120,037
)
(52,394
)
(41,759
)
(41,635
)
Financing activities:
Proceeds from issuance of second lien notes
550,000
-
-
-
Repayments of revolving credit facility
-
-
-
(442,034
)
Borrowings on exit facilities
40,000
94,000
50,000
200,000
Extinguishment of long-term debt
(192,182
)
-
-
-
Repayments on exit facilities
(214,000
)
-
(70,000
)
-
Debt issuance costs and arrangement fees
(17,242
)
-
-
(6,218
)
Issuance of exit notes
-
-
-
75,000
Principal payments of finance lease liabilities
(16,965
)
(15,865
)
(9,845
)
-
Net cash provided by (used in) financing activities
149,611
78,135
(29,845
)
(173,252
)
Net change in cash, cash equivalents and restricted cash
41,354
34,605
(52,700
)
(314,951
)
Cash, cash equivalents and restricted cash, beginning of period
97,334
62,729
115,429
430,380
Cash, cash equivalents and restricted cash, end of period
$
138,688
$
97,334
$
62,729
$
115,429
The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
Diamond Offshore Drilling, Inc. provides contract drilling services to the energy industry around the globe with a fleet of 13 offshore drilling rigs, consisting of four owned drillships, seven owned semisubmersible rigs and two managed rigs.
Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these Consolidated Financial Statements and Notes 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, revenues, and expenses during the reporting period. Actual results could differ from those estimated.
Cash and Cash Equivalents
We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.
The effect of exchange rate changes on cash balances held in foreign currencies was not material for the Successor periods for the years ended December 31, 2023 and December 31, 2022.
Asset Held for Sale
We reported the $1.0 million carrying value of the Ocean Monarch as an “Asset held for sale” in our Successor Consolidated Balance Sheets at December 31, 2023. We are marketing the rig for recycling and expect to complete a sale in early 2024.
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 periods for the years ended December 31, 2023 and December 31, 2022, we capitalized $124.3 million and $69.1 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 on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from 3 to 30 years.
Impairment of Long-Lived Assets
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, a change in the economic useful life of a rig, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project, reactivation or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
•dayrate by rig;
•utilization rate by rig if active, warm-stacked or cold-stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);
•the per day operating cost for each rig if active, warm-stacked or cold-stacked;
•the estimated annual cost for rig replacements and/or enhancement programs;
•the estimated maintenance and inspection or other reactivation costs associated with a rig returning to work;
•the remaining economic useful life of a rig;
•salvage value for each rig; and
•estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability-weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment.
Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil
and gas prices, cancellations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, capital expenditures required due to advances in offshore drilling technology, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. See Note 4 “Asset Impairments.”
Survey Costs
Concurrent with emergence from bankruptcy, the Successor entity adopted a new policy providing for the deferral and amortization of costs associated with planned periodic inspections of its drilling rigs (or vessels) to ensure compliance with applicable regulations and maintain certifications for vessels with classification societies that typically occur on five-year or two-and-one-half year intervals. These costs include mobilization of the vessel into the shipyard, drydocking, support services while in shipyard and the associated survey or inspection costs necessary to maintain class certifications. These recertification costs are typically incurred while the vessel is in drydock and may be performed concurrent with other vessel maintenance and improvement activities. Costs related to the recertification of vessels are deferred and amortized over the survey interval on a straight-line basis. Maintenance costs incurred at the time of the recertification drydocking that are not related to the recertification of the vessel are expensed as incurred. Costs for vessel improvements that either extend the vessel’s useful life or increase the vessel's functionality are capitalized and depreciated. The Predecessor’s previous policy was to expense vessel recertification costs in the period incurred.
For the Successor periods for the years ended December 31, 2023 and December 31, 2022, we deferred $3.5 million and $3.3 million, respectively, in survey costs. At December 31, 2023 and December 31, 2022, deferred survey costs of $1.4 million and $0.8 million, respectively, were reported in “Prepaid expenses and other current assets” and $4.3 million and $2.5 million, respectively, were reported in “Other assets” in our Successor Consolidated Balance Sheets. We amortized $1.1 million and $0.7 million in deferred survey costs as “Contract drilling, excluding depreciation” in the Successor’s Consolidated Statements of Operations for the years ended December 31, 2023 and 2022, respectively.
Lease Accounting and Revenue Recognition
Financial Accounting Standards Board (or FASB) Accounting Standards Update (or ASU), No. 2016-02, Leases (Topic 842) (or 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). See Note 3 “Revenue from Contracts with Customers.”
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 8 “Financial Instruments and Fair Value Disclosures.”
Debt Issuance Costs
Deferred costs associated with our credit facility are presented in “Other assets” in the Successor's Consolidated Balance Sheets at December 31, 2023 and 2022 and amortized as interest expense over the respective terms of the credit facility. Deferred costs associated with our other long-term debt are presented in the Successor's Consolidated Balance Sheets at December 31, 2023 and 2022 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 10 “Long-Term 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 13 “Income Taxes.”
Comprehensive Loss
Comprehensive (loss) income is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive loss for the Successor periods for the years ended December 31, 2023 and 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 includes net losses and unrealized holding gains on marketable securities.
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.
Accounting Principles Not Yet Adopted
In December 2023, the FASB issued ASU No. 2023-09, Income Tax (Topic 740): Improvements to Income Tax Disclosures (or ASU 2023-09). ASU 2023-09 requires business entities on an annual basis to (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet certain quantitative thresholds. The new guidance is effective for public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (or ASU 2023-07). ASU 2023-07 modifies the disclosure and presentation requirements of reportable segments and requires the disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss. In addition, the new guidance enhances interim disclosure requirements, clarifies circumstances in which an entity
can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and other disclosure requirements. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.
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. Concurrently, the Debtors entered into the Backstop Agreement (as defined in the PSA) with certain holders of Senior Notes and entered into the Commitment Letter (as defined in the PSA) with certain holders of RCF Claims to provide exit financing upon emergence from bankruptcy. The Debtors filed a joint Chapter 11 plan of reorganization with the Bankruptcy Court on January 22, 2021, which was subsequently amended on February 24, 2021 and February 26, 2021 (or the Plan). On March 23, 2021, the Debtors filed the plan supplement for the Plan with the Bankruptcy Court, which was subsequently amended on April 6, 2021 and April 22, 2021 (or the Plan Supplement).
Chapter 11 Emergence
On April 8, 2021, the Bankruptcy Court entered an order confirming the Plan (or the Confirmation Order). On April 23, 2021 (or the Effective Date), all conditions precedent to the Plan were satisfied, the Plan became effective in accordance with its terms, and the Debtors emerged from Chapter 11 reorganization.
New Diamond Common Shares and New Warrants
On the Effective Date, in connection with the effectiveness of, and pursuant to the terms of, the Plan and the Confirmation Order, the Company’s common stock outstanding immediately before the Effective Date was canceled. The new organizational documents of the Reorganized Company (as defined below) became effective, authorizing the issuance of shares of common stock representing 100% of the equity interests in the Reorganized Company (or the New Diamond Common Shares). Pursuant to the Warrant Agreement (as defined below), the Emergence Warrants (as defined below) were issued by the Company to holders of existing shares of common stock in the amounts, and on the terms, set forth in the Plan and the Plan Supplement. Thus, the Company, as reorganized on the Effective Date in accordance with the Plan (or the Reorganized Company), issued the New Diamond Common Shares and the Emergence Warrants, and the 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (or the First Lien Notes) were issued by Diamond Foreign Asset Company (or DFAC), a Cayman Islands exempted company limited by shares that is a wholly-owned subsidiary of the Company, 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 has 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.
New Debt at Emergence
On the Effective Date, pursuant to the terms of the Plan, the Company and DFAC entered into the following debt instruments:
•a senior secured revolving credit agreement (or the Exit Revolving Credit Agreement), which provided for a $400.0 million senior secured revolving credit facility (or the Exit RCF);
•a senior secured term loan credit agreement (or the Exit Term Loan Credit Agreement), which provided 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 was 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 were issuable 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, 2023.
On September 21, 2023, DFAC and DFLLC, (or, together with DFAC, the Issuers), issued $550.0 million aggregate principal amount of 8.5% Senior Secured Second Lien Notes due 2030 (or Second Lien Notes) in a private placement (or the Notes Offering). We used the proceeds from the Notes Offering to fully repay outstanding borrowings under and terminate our Exit Term Loan Credit Facility, redeem in full our First Lien Notes and repay all amounts outstanding under the Exit RCF. See Note 10 “Long-Term 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) canceled (or otherwise eliminated) and received no distribution under the Plan or (ii) Reinstated at the Debtors’ option.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with ASC 852 - Reorganizations, 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 required 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 differed 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 are not 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. 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).
3. Revenue from Contracts with Customers
Our contracts with customers provide for an offshore drilling rig and drilling services on a dayrate contract basis. The integrated services provided under our contracts primarily include (i) provision of an offshore drilling rig, the work crew and supplies of equipment and services necessary to operate the rig, (ii) mobilization and demobilization of the rig to and from the drill site and (iii) performance of rig preparation activities and/or modifications required for each contract.
We have concluded that our drilling contracts contain a lease component. However, we have elected to apply the practical expedient provided under ASU 2016-02 to not separate the lease and non-lease components and apply the revenue recognition guidance in Topic 606.
Therefore, we account for the integrated services provided within our drilling contracts as a single performance obligation satisfied over time, comprised of a series of distinct time increments in which we provide drilling services. The total transaction price is recognized for each drilling contract by estimating both fixed and variable consideration expected to be earned over the contract term (which is the period we estimate to be benefited from the corresponding activities and generally ranges from two to 60 months).
The amount estimated for variable consideration may be constrained (reduced) and is only recognized in revenue to the extent that it is probable that a significant reversal 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. See below for further discussion regarding the allocation of the transaction price to the remaining performance obligations.
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, restricted by equipment breakdowns, adverse environmental conditions, etc. 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.
Certain of our contracts contain performance based incentives, whereby we may earn a bonus or incur penalties based on pre-established performance metrics. Consideration related to the performance incentive is generally recognized in the specific time period to which the performance criteria were attributed.
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. We record a contract liability for mobilization fees received and amortize such on a straight-line basis to contract drilling revenue as services are rendered over the 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 as contract drilling revenue on a straight-line basis over the 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 upfront fees received, which is amortized on a straight-line basis to contract drilling revenue over the 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 the upfront fees received and recognize them on a straight-line basis to contract drilling revenue over the term of the related drilling contract.
Termination Fees. Certain of our drilling contracts may be cancelable for the convenience of the customer, typically with the payment of an early termination fee. Termination fees are not considered distinct within the context of the contract and are typically recognized ratably over the remaining term of the contract once notice of termination is received, and such fee can be reasonably estimated and collection is probable.
During the Successor year ended December 31, 2023, we recognized fees of $12.5 million and $6.7 million related to the termination of contracts for the Ocean Patriot and Ocean Apex, respectively.
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. 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 recognized 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.
Revenues Related to Managed Rigs. In May 2021, we entered into an arrangement with an offshore drilling company whereby we would provide management and marketing services (or the MMSA) for certain of their rigs. The MMSA provided for (i) a daily fixed fee, based on status of the drilling rig, (ii) marketing fees based on a percentage of the earned dayrate of a drilling contract secured by us on behalf of the rig owner, (iii) a variable management fee and (iv) reimbursement of direct cost incurred. The fixed and variable fees were recognized in “Contract Drilling Revenue” in our Consolidated Statements of Operations. Revenue related to the reimbursement of expenses incurred and billed to the rig owner were recorded as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.
We may enter into certain drilling contracts directly with a customer. We are considered principal or agent of these transactions and recognize revenue under the terms of the contract. Such amounts are reported as "Contract Drilling Revenue" in our Consolidated Statements of Operations. In addition, we charter the related drilling rig from the rig owner to satisfy our performance obligation under the contract. We have determined that the arrangement to charter the rig is an operating lease, and the related charter fee has been reported as lease expense within "Contract Drilling, excluding depreciation" in our Consolidated Statements of Operations.
The marketing arrangement for both rigs was terminated in 2023, and the charter agreement for the West Auriga was terminated in 2024. The West Auriga is expected to be returned to the rig owner upon completion of its drilling contract during the first quarter of 2024.
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. 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):
December 31,
Trade receivables
$
253,367
$
155,956
Current contract assets (1)
2,575
Noncurrent contract assets (1)
-
-
Current contract liabilities (deferred revenue) (1)
(12,634
)
(11,513
)
Noncurrent contract liabilities (deferred revenue) (1)
(3,947
)
(487
)
(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, 2023 and 2022.
Significant changes in net contract assets and the contract liabilities balances during the period are as follows (in thousands):
Contract
Contract
Assets
Liabilities
Balance as of January 1, 2022
$
1,835
$
(48,293
)
Decrease due to amortization of revenue included in the beginning contract liability balance
-
26,909
Increase due to cash received, excluding amounts recognized as revenue during the period
-
(2,444
)
Increase due to revenue recognized during the period but contingent on future performance
6,618
-
Decrease due to transfer to receivables during the period
(8,312
)
-
Adjustments (1)
-
11,828
Balance as of December 31, 2022
$
$
(12,000
)
Decrease due to amortization of revenue included in the beginning contract liability balance
-
11,512
Increase due to cash received, excluding amounts recognized as revenue during the period
-
(16,093
)
Increase due to revenue recognized during the period but contingent on future performance
12,177
-
Decrease due to transfer to receivables during the period
(9,743
)
-
Balance as of December 31, 2023
$
2,575
$
(16,581
)
(1) Upon commencement of drilling operations, the MMSA for the managed rigs was suspended and replaced by a charter agreement for the duration of the contract. As a result, we reclassified $11.1 million previously recorded
as a contract liability to “Contract advances,” which was reported as a component of “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2022.
Deferred Contract Costs
Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the term of the related drilling contract. Such deferred contract costs in the amount of $20.6 million and $6.2 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheets at December 31, 2023. Deferred contract costs in the amount of $14.4 million and $0.3 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheets at December 31, 2022. The amount of amortization of such costs was $16.2 million and $7.3 million for the years ended December 31, 2023 and 2022, respectively. 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, 2023 (in thousands):
For the Year Ending December 31,
Total
Mobilization and contract
preparation revenue
$
6,256
$
1,350
$
1,350
$
1,235
$
10,191
Capital modification revenue
4,381
-
-
-
4,381
Blended rate/other revenue
2,009
-
-
-
2,009
Demobilization and other deferred revenue
1,049
Total
$
13,118
$
1,548
$
1,548
$
1,416
$
17,630
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 has also been 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, 2023. 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.
4. Asset Impairments
For the Successor years ended December 31, 2023 and 2022, we did not identify any indicators that the carrying amounts of our assets were not recoverable, and, thus, recorded no impairment losses for each of the periods then ended, respectively.
During the first quarter of 2021, we identified indicators that the carrying amounts of certain of our assets may not be recoverable and evaluated three of our drilling rigs with indicators of impairment. Based on our assumptions
and analysis at that time, we determined that the carrying value of one of these rigs was impaired. We recorded an asset impairment aggregating $197.0 million for the Predecessor period from January 1, 2021 through April 23, 2021 related to this rig.
Pursuant to fresh start accounting, our long-lived assets, including our drilling rigs, were valued at their estimated fair value on the Effective Date based on assumptions and market factors that we believed to be accurate at that time. On the Effective Date, the remaining economic useful life of each individual rig was validated or revised, if so indicated. Subsequently, at the end of 2021, we reviewed the marketability, age and physical condition of certain of our rigs in conjunction with other factors specific to the geographic markets in which our rigs are capable of operating and determined that, based on circumstances that arose in the fourth quarter of 2021, which we believed to be other than temporary, the economic useful lives of certain of the rigs in our fleet were materially different than that determined at the Effective Date. At December 31, 2021, we identified three semisubmersible rigs for which we believed a change in the economic useful life was appropriate. In connection with this reassessment, we evaluated each rig for recoverability and determined that the carrying values of two of these rigs were impaired. We recorded an aggregate impairment loss of $132.4 million in the Successor period from April 24, 2021 through December 31, 2021 to write down the carrying value of these rigs to their estimated fair values. In addition, we reviewed one other rig with an indicator of impairment and determined that no impairment had occurred at December 31, 2021.
We estimated the fair values of the impaired rigs using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. These calculations utilized significant unobservable inputs, including management’s assumptions related to estimated dayrate revenue, rig utilization and, when applicable, estimated capital expenditures, repair and regulatory survey costs, as well as estimated proceeds that may be received on ultimate disposition of the rig. Our fair value estimate was representative of a Level 3 fair value measurement due to the significant level of estimation involved and the lack of transparency as to the inputs used.
See Note 1 “General Information - Impairment of Long-Lived Assets” and Note 8 “Financial Instruments and Fair Value Disclosures.”
5. Supplemental Financial Information
Consolidated Balance Sheets Information
Accounts receivable, net of allowance for bad debts, consists of the following (in thousands):
December 31,
Trade receivables
$
253,367
$
155,956
Value added tax receivables
5,256
6,075
Related party receivables
Federal income tax receivables
-
9,450
Other
1,346
6,121
260,124
177,675
Allowance for credit losses
(5,801
)
(5,622
)
Total
$
254,323
$
172,053
The allowance for credit losses at December 31, 2023 and 2022 represents our current estimate of credit losses associated with our “Trade receivables” and “Current contract assets.” See Note 8 “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):
December 31,
Deferred contract costs
20,552
14,373
Collateral deposit
11,857
-
Prepaid taxes
10,868
16,922
Rig spare parts and supplies
4,694
5,091
Prepaid rig costs
3,668
4,001
Prepaid insurance
3,437
3,022
Current contract assets
2,575
Deferred survey costs
1,418
Software maintenance agreements and subscriptions
1,408
1,212
Other
2,935
3,095
Total
$
63,412
$
48,695
Accrued liabilities consist of the following (in thousands):
December 31,
Contract advances
$
63,618
$
52,743
Rig operating costs
42,893
39,288
Payroll and benefits
35,215
29,408
Interest payable
13,013
1,897
Deferred revenue
12,634
11,513
Accrued capital project/upgrade costs
10,766
8,419
Current operating lease liability
8,436
13,480
Personal injury and other claims
7,391
3,738
Shorebase and administrative costs
5,699
4,365
Deposit for equipment sale
1,977
1,670
Other
1,694
Total
$
203,336
$
166,785
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
Year Ended
Period from April 24
Period from January 1
December 31,
through December 31,
through April 23,
Accrued but unpaid capital expenditures at period end
$
10,766
$
8,419
$
2,219
$
18,617
Accrued but unpaid debt issuance costs and arrangement fees (1)
-
-
-
7,588
Common stock withheld for payroll tax obligations (2)
4,241
4,252
-
-
Cash interest payments
30,949
27,767
13,671
37,593
Cash paid for reorganization items, net
-
-
36,154
37,566
Cash income taxes paid (refunded), net:
Foreign
7,449
13,178
1,969
3,460
U.S. federal
(2,446
)
-
State
-
-
(34
)
(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 302,833 and 563,727 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of equity awards in the years ended December 31, 2023 and 2022, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheets at December 31, 2023 and 2022, respectively.
6. 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
The Diamond Offshore Drilling, Inc. 2021 Long-Term Stock Incentive Plan (or 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, which may or may not be participating securities. The aggregate number of shares of Common Stock initially available for issuance pursuant to awards under the Equity Incentive Plan was 11,111,111.
Total compensation cost recognized for all awards under the Equity Incentive Plan for the Successor periods for the years ended December 31, 2023 and 2022 and for the period from April 24, 2021 to December 31, 2021 was $14.2 million, $20.2 million and $10.8 million, respectively. Tax benefits recognized for the Successor periods for the years ended December 31, 2023 and 2022 and for the period from April 24, 2021 to December 31, 2021 were $2.5 million, $2.9 million and $2.0 million, respectively. As of December 31, 2023, total unrecognized compensation cost related to non-vested awards under the Equity Incentive Plan aggregated $10.7 million, which we expect to recognize over a weighted average period of one year.
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. As of December 31, 2023, an aggregate 318,292 time-vesting RSU awards were outstanding with respect to awards to our non-employee members of the Board (or Board RSUs). The Board RSUs vest and become non-forfeitable on the first 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.
Effective July 1, 2021, the Board approved a new key employee retention and incentive plan covering executive officers and certain non-executive key employees. During the Successor periods for the years ended December 31, 2023 and 2022 and from April 24, 2021 to December 31, 2021, we granted 593,205, 535,516 and 1,916,043 time-vesting RSUs, respectively, to our executive officers and other non-key executive employees. The RSUs vest annually over a period of three years from the grant date.
Restricted Stock Awards. 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 in 2021, which had fully vested by May 2023. 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, 2023 and changes during the year then ended is as follows:
Number
of Awards
Weighted
-Average
Grant Date
Fair Value
Per Share
Nonvested awards at January 1, 2023
1,945,138
$
8.20
Granted
692,236
$
11.34
Vested
(854,293
)
$
8.31
Forfeited
(98,460
)
$
8.31
Nonvested awards at December 31, 2023
1,684,621
$
6.81
The weighted average grant-date fair value per share of restricted stock awards granted during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 to December 31, 2021 was $11.34, $6.68 and $8.75, respectively. The total fair value of the restricted stock awards that vested during the Successor periods for the years ended December 31, 2023 and 2022 and for the period from April 24, 2021 to December 31, 2021 was $11.3 million, $3.9 million and $0.6 million, respectively.
Performance-Vesting Awards
RSUs. During the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 to December 31, 2021, we granted 431,241, 709,148 and 1,733,404 performance-vesting RSU awards, respectively.
The performance-vesting RSUs granted during years ended December 31, 2023 and 2022 will vest at the end of a three-year period upon the achievement of certain market conditions and continuous employment of the award holder. The fair value of these shares was estimated using a Monte Carlo simulation.
The performance-vesting RSUs granted during the Successor period from April 24, 2021 to December 31, 2021 vest annually over a three-year cycle and are distributed based on performance metrics and continuous employment. The fair value of these shares was estimated based on the fair market value of our Common Stock on the date of grant.
A summary of performance-vesting RSU activity under the Equity Incentive Plan as of December 31, 2023 and changes during the year then ended is as follows:
Number
of Awards
Weighted
-Average
Grant Date
Fair Value
Per Share
Nonvested awards at January 1, 2023
1,521,297
$
7.42
Granted
431,241
$
13.99
Vested
(419,736
)
$
8.75
Forfeited
(24,453
)
$
8.75
Nonvested awards at December 31, 2023
1,508,349
$
4.62
The weighted average grant-date fair value per share of performance awards granted during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 to December 31, 2021 was $13.99, $5.71 and $8.75, respectively. The total fair value of performance awards vested during Successor years ended December 31, 2023 and 2022 was $6.5 million and $3.2 million, respectively.
Restricted Stock. In May 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 vested upon achievement of both a market and performance condition. Vesting was contingent upon certain conditions (as defined in the award agreement under the Equity Incentive Plan). All vesting conditions have now been satisfied and 30,370 restricted shares and 747,407 restricted shares vested during 2023 and 2022, respectively. The weighted-average grant-date fair value of these performance-vesting restricted stock awards was $6.89 per share, or $5.4 million in the aggregate, which we recognized as compensation expense during the Successor year ended December 31, 2022. The total fair value of the awards that vested during the Successor years ended December 31, 2023 and 2022 was $0.4 million and $6.2 million, respectively.
The performance-vesting restricted stock awards granted during the Successor years ended December 31, 2023 and 2022 were valued using a Monte Carlo simulation assuming a Geometric Brownian Motion in a risk-neutral framework and using the following assumptions:
Awards granted
Expected life of awards (in years)
Expected volatility
70.50
%
75.00
%
Risk-free interest rate
3.70
%
2.71
%
7. Loss Per Share
We present basic and diluted loss per share on our Consolidated Statements of Operations. Basic loss per share excludes dilution and is computed by dividing net loss by the weighted-average number of shares of common stock
outstanding for the period. We experienced net losses for the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021. We have excluded shares of common stock issuable upon exercise of outstanding stock appreciation rights and vesting of outstanding restricted stock units from the calculation of weighted-average shares because their inclusion would be antidilutive.
8. Financial Instruments and Fair Value Disclosures
Concentrations of Credit Risk and Allowance for Credit Losses
Our credit risk arises primarily from trade receivables. The market for our services is the offshore oil and gas industry, and our customer base consists primarily of major and independent oil and gas companies, as well as government-owned oil companies. At December 31, 2023, we believe that we had potentially significant concentrations of credit risk due to the number of rigs we currently had contracted and the 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 currently have one customer for which prepayments are required and full payment is due prior to commencement of the contract in mid-2024. At December 31, 2023, no amounts were owed by this customer.
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.
Pursuant to ASU 2016-13, we review 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 develop a credit loss factor using a weighted-average ratio of our actual credit losses to revenues during the look-back period. We also consider 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 ASU 2016-13 and its related amendments (or collectively, 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 calculate a credit loss factor based on historical loss rate information and apply 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, 2023, $11.1 million in trade receivables were considered past due by 30 days or more, of which $5.5 million have been fully reserved. The remaining $5.6 million were less than a year past due and considered collectible. For purposes of calculating our current estimate of credit losses at December 31, 2023 and 2022, all trade receivables, except for those fully reserved, were deemed to be in a single risk pool based on their credit ratings at each respective period. Our total allowance for credit losses was $5.8 million and $5.6 million at December 31, 2023 and 2022, including $0.3 million and $0.2 million at December 31, 2023 and 2022, respectively, related to our current estimate of credit losses under CECL. See Note 5 “Supplemental Financial Information - Consolidated Balance Sheets 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 period from January 1, 2021 through April 23, 2021. 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 period from January 1, 2021 through April 23, 2021. See Note 4 “Asset Impairments.”
Assets and liabilities measured at fair value are summarized below (in thousands).
Successor
December 31, 2023
Fair Value Measurements Using
Level 1
Level 2
Level 3
Assets and Liabilities at
Fair Value
Total Losses for Year Ended (2)
Recurring fair value measurements
Short-term investments (1)
$
92,308
$
-
$
-
$
92,308
$
-
Liability-classified Director restricted stock units (2)
$
(1,259
)
$
-
$
-
$
(1,259
)
$
(252
)
Successor
December 31, 2022
Fair Value Measurements Using
Level 1
Level 2
Level 3
Assets and Liabilities at
Fair Value
Total Losses for Year Ended (2)
Recurring fair value measurements
Liability-classified Director restricted stock units (2)
$
(1,258
)
$
-
$
-
$
(1,258
)
$
(201
)
(1)Represents short-term investments in debt securities classified as available for sale. As the original maturities of these debt securities are three months or less, we have reported our $92.3 million investment in these debt securities as Cash and cash equivalents in our Consolidated Balance Sheets at December 31, 2023.
(2)The fair value of restricted stock units was estimated based on the quoted market price of our Common Stock at the respective balance sheet date. The total loss for the year includes an increase in stock compensation expense due to the “marking-to-market” of liability-classified restricted stock units granted to our non-employee directors on a recurring basis.
We believe that the carrying amounts of our other financial assets and liabilities (excluding our Second Lien Notes, Exit Term Loans and First Lien 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 Second Lien Notes, Exit Term Loans and First Lien Notes would be considered Level 2 liabilities. The fair value of these instruments was derived using a third-party pricing service at December 31, 2023 and 2022. 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.
Fair values and related carrying values of our Second Lien Notes, Exit Term Loans and First Lien Notes (see Note 10 "Long-Term Debt") are shown below (in millions).
December 31,
Fair
Value
Carrying
Value
Fair
Value
Carrying
Value
Second Lien Notes
$
562.6
$
550.0
$
-
$
-
Exit Term Loans
-
-
91.1
100.0
First Lien Notes
-
-
78.3
85.3
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.
9. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows (in thousands):
December 31,
Drilling rigs and equipment
$
1,244,798
$
1,126,793
Finance lease right of use asset
174,571
174,571
Land and buildings
10,040
10,001
Office equipment and other
5,180
2,515
Cost
1,434,589
1,313,880
Less: accumulated depreciation
(278,221
)
(171,972
)
Drilling and other property and equipment, net
$
1,156,368
$
1,141,908
10. Long-Term Debt
At December 31, 2023 and 2022, the carrying value of our long-term debt, net of unamortized discount, premium and debt issuance costs, was comprised as follows (in thousands):
December 31,
$550 Million Senior Secured Second Lien Notes due 2030
$
533,514
$
-
Borrowings under Exit RCF
-
177,478
$100.0 Million Exit Term Loan
-
99,190
9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027
-
83,976
Total Long-term debt
$
533,514
$
360,644
At December 31, 2023, the aggregate annual maturity of our Senior Secured Second Lien Notes, excluding net debt issuance costs of $16.5 million, was as follows (in thousands):
Year ending December 31,
Aggregate Principal Amount
-
-
-
-
-
Thereafter
550,000
Total maturities of long-term debt
$
550,000
Second Lien Notes
On September 21, 2023, DFAC and DFLLC (which we refer to collectively as the Issuers) issued $550 million aggregate principal amount of 8.5% Senior Secured Second Lien Notes due 2030 (which we refer to as the Second Lien Notes) in a private placement. The Second Lien Notes were issued at par for net proceeds of approximately $540.0 million after deduction of certain estimated offering expenses. The Second Lien Notes mature on October 1, 2030, and interest is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2024.
The Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by Diamond Offshore Drilling, Inc. (or DODI) and each of its existing restricted subsidiaries (other than the Issuers) and by certain of DODI’s future restricted subsidiaries (other than the Issuers) that guarantee any debt of the Issuers or any guarantor under any syndicated credit facility or capital markets debt in an aggregate principal amount in excess of a certain amount (or, collectively, the Subsidiary Guarantors and, together with DODI, the Guarantors). The Second Lien Notes and the related guarantees are secured on a second-priority basis, subject to certain permitted liens, by substantially all the assets of, and equity interests in, the Issuers and the Subsidiary Guarantors.
On or after October 1, 2026, the Issuers may, at their option, redeem all or any portion of the Second Lien Notes from time to time upon not less than 10 days nor more than 60 days prior notice, at the redemption prices set forth below, plus accrued and unpaid interest if any, to, but excluding, the redemption date. The following prices are for Second Lien Notes redeemed during the 12-month period commencing on October 1 of the years set forth below, and are expressed as percentages of principal amount:
Redemption Year
Price
104.25
%
102.13
%
2028 and thereafter
100.00
%
At any time and from time to time, prior to October 1, 2026, the Issuers may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the Second Lien Notes issued under the Indenture (as defined below) (including any additional Second Lien Notes, if any) with an amount equal to or less than the net cash proceeds of one or more equity offerings, at a redemption price equal to 108.500% of the principal amount thereof, plus accrued and unpaid interest thereon, if any, to but excluding, the redemption date provided; however, that immediately after giving effect to any such redemption, at least 65% of the original aggregate principal amount of Second Lien Notes issued on the issue date (excluding Second Lien Notes held by DODI or its subsidiaries) remains outstanding.
In addition, at any time prior to October 1, 2026, the Issuers may redeem up to 10% of the original aggregate principal amount of the Second Lien Notes issued under the Indenture (including additional Second Lien Notes, if any) during any twelve-month period at a redemption price equal to 103.000% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.
At any time prior to October 1, 2026, the Issuers may redeem some or all of the Second Lien Notes at a price equal to 100% of the principal amount of the Second Lien Notes redeemed, plus accrued and unpaid interest, if any, to, but not including, the redemption date, plus a “make-whole” premium.
The Second Lien Notes are governed by an indenture, dated as of September 21, 2023 (or the Indenture), entered into by the Issuers, DODI and certain of its subsidiaries named therein and HSBC Bank USA, National Association (or HSBC), as trustee and collateral agent. The Indenture contains covenants that, among other things, restrict DODI’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue certain preferred stock; (ii) incur or create liens; (iii) make certain dividends, distributions, investments and other restricted payments; (iv) sell or otherwise dispose of certain assets; (v) engage in certain transactions with affiliates; and (vi) merge, consolidate, amalgamate or sell, transfer, lease or otherwise dispose of all or substantially all of DODI’s assets. These covenants are subject to important exceptions and qualifications. In addition, many of these covenants will be suspended with respect to the Second Lien Notes during any time that the Second Lien Notes have investment grade ratings from at least two rating agencies and no default with respect to the Second Lien Notes has occurred and is continuing.
Upon the occurrence of a certain Change of Control Triggering Event (as defined in the Indenture), the Issuers may be required to make an offer to repurchase all of the Second Lien Notes then outstanding at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
We used a portion of the net proceeds from the Notes Offering to fully repay outstanding borrowings under and terminate our Exit Term Loan Credit Facility, redeem in full our 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (which we refer to as the First Lien Notes) and repay all amounts outstanding under the Exit RCF. The remaining net proceeds will be used for general corporate purposes.
The Second Lien Notes were valued at par and presented net of unamortized debt issuance costs of $17.0 million, which are being amortized as interest expense over the stated maturity of the Second Lien Notes using the effective interest method. At December 31, 2023, the effective interest rate on the Second Lien Notes was 9.09%.
Amended Revolving Credit Agreement
On April 23, 2021, we entered into the Exit Revolving Credit Agreement, which provided for a $400.0 million senior secured revolving credit facility and also originally provided for certain lenders (or the LC Lenders) to issue up to $100.0 million of letters of credit thereunder (which we refer to as the Exit RCF). Prior to the Notes Offering, three of the four initial LC Lenders had resigned, reducing availability to issue letters of credit under the Exit RCF to $25.0 million.
On September 12, 2023, DFAC, as borrower, DODI, as parent, certain of the lenders party thereto, and HSBC, as administrative agent and collateral agent, entered into an amendment (or the Credit Agreement Amendment) to the Exit Revolving Credit Agreement. The Credit Agreement Amendment amended the Exit RCF (or, as amended, the Amended RCF) to, among other things, (i) reduce the aggregate commitment of the lenders thereunder from $400.0 million to $300.0 million, (ii) permit the Notes Offering and (iii) permit us to incur up to an aggregate of $50.0 million of indebtedness in respect of outstanding letters of credit that may be issued on our behalf outside of the
Amended RCF. The Credit Agreement Amendment became effective concurrently with the consummation of the Notes Offering, which was conditioned on the Credit Agreement Amendment becoming effective.
Borrowings under the Amended 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 Amended 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 Amended RCF) would exceed $125.0 million, (ii) the Amended RCF Collateral Coverage Ratio (as defined below) would be less than 2.00 to 1.00 or (iii) the Total Collateral Coverage Ratio (as defined below) would be less than 1.30 to 1.00.
Available Cash in excess of $125.0 million is also required to be applied periodically to prepay loans. The loans under the Amended RCF may be voluntarily prepaid and the commitments thereunder voluntarily terminated or reduced by DFAC at any time without premium or penalty, other than customary breakage costs.
The Amended RCF obligates DODI, DFAC and their 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 Amended RCF), to (b) the aggregate outstanding principal amount of all Loans and L/C Obligations (each as defined in the Amended RCF) thereunder (or the Amended RCF 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 Second Lien Notes as of such date (or the Total Collateral Coverage Ratio) not permitted to be less than 1.30 to 1.00.
The Amended RCF contains negative covenants that limit, among other things, the ability of each of DODI, DFAC and their 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) prepay, 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 Amended RCF 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.
Loans under the Amended RCF bear interest at (i) the Base Rate plus the Applicable Margin (each as defined in the Amended RCF) or (ii) Adjusted Term SOFR (as defined in the Amended RCF) plus the Applicable Margin.
DFAC is required to pay a quarterly commitment fee under the Amended RCF, which accrues at a rate per annum equal to 0.50% on the average daily unused portion of the lenders’ commitments under the Amended RCF. DFAC is also required to pay customary letter of credit and fronting fees.
On September 21, 2023, we repaid the aggregate principal amount of borrowings outstanding under the Amended RCF of approximately $189.0 million plus accrued and unpaid interest thereon through the repayment date in full with a portion of the proceeds of the Notes Offering. In addition, we wrote off a pro rata portion of unamortized deferred debt arrangement fees related to the reduction in borrowing capacity under the Amended RCF. We reported the $1.3
million write-off of fees as “Loss on extinguishment of long-term debt” in our Consolidated Statements of Operations for the year ended December 31, 2023.
On October 24, 2023, Barclays Bank PLC (or Barclays), gave notice of its resignation as an LC Lender under the Amended RCF. Our capacity for issuing additional letters of credit under the Amended RCF has been reduced to zero. However, the Amended RCF permits us to incur up to $50.0 million of indebtedness in respect of outstanding letters of credit that may be issued on our behalf outside of the Amended RCF.
At December 31, 2023 and February 23, 2024, we had no borrowings outstanding under the Amended RCF and had utilized $1.9 million for the issuance of a letter of credit. The outstanding letter of credit will expire on maturity in May 2024, unless replaced. As of February 23, 2024, approximately $298.1 million was available for borrowings under the Amended RCF subject to its terms and conditions. There was no capacity to issue additional letters of credit under the Amended RCF.
At December 31, 2023, we were in compliance with all covenants under the Second Lien Notes and Amended RCF.
$100.0 Million Exit Term Loan
Our Exit Term Loan Credit Agreement provided for a $100.0 million senior secured term loan credit facility which was used in its entirety to refinance a portion of the prepetition revolving credit facility. The Exit Term Loan Credit Facility was set to mature on April 22, 2027.
The Exit Term Loans bore interest at a rate per annum equal to the applicable margin plus, at the borrower’s option, either (a) the reserve-adjusted LIBOR Rate (as defined in the Exit Term Loan Credit Agreement) subject to a floor of 1.00% (or LIBOR Rate Term Loans), or (b) a base rate (or Base Rate Term Loans), subject to a floor of 2.00%, determined as the greatest of (i) the Wells Fargo Prime Rate (as defined in the Exit Term Loan Credit Agreement), (ii) the federal funds effective rate plus ½ of 1.00%, and (iii) the reserve-adjusted one-month LIBOR Rate plus 1.00%. The margin applicable to LIBOR Rate Term Loans was 6.00%. Interest on Base Rate Term Loans was paid quarterly.
In September 2023, we used a portion of the proceeds from the Notes Offering to repay all outstanding Exit Term Loans, aggregating $100.0 million, and unpaid interest thereon through the repayment date. As a result of the repayment of the Exit Term Loans, we wrote off $0.7 million in unamortized deferred arrangement fees as “Loss on extinguishment of long-term debt” in our Consolidated Statements of Operations for the Successor year ended December 31, 2023.
9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027
On the Effective Date, we issued the 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes in the aggregate amount of $85.3 million with an original maturity date of April 22, 2027. The First Lien Notes were issued at 101% of par value.
Interest on the First Lien Notes accrued at a rate of 9.00% per annum, assuming a cash interest payment option, and was payable semi-annually in arrears on April 30 and October 31 of each year. In addition, the Issuers incurred 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.
We redeemed the First Lien Notes in full, in the aggregate principal amount of $85.3 million, including accrued and unpaid interest through September 21, 2023, at 104% in accordance with the First Lien Notes Indenture with a portion of the proceeds of the Notes Offering. The $3.4 million call premium paid on retirement of the First Lien Notes, in addition to the write-off of $(0.6) million and $1.7 million of unamortized premium and deferred arrangement fees, respectively, were reported as “Loss on extinguishment of long-term debt” in our Consolidated Statements of Operations for the Successor year ended December 31, 2023.
Upon retirement of the First Lien Notes, unfunded delayed draw commitments aggregating $39.7 million under the First Lien Notes Indenture also terminated.
Collateral Agency Agreement
On September 21, 2023, DODI, the Issuers and the subsidiary guarantors that are also grantors of collateral entered into an Amended and Restated Collateral Agency and Intercreditor Agreement with HSB as trustee, collateral agent and administrative agent under the Amended RCF (or the Collateral Agency Agreement). The Collateral Agency Agreement, among other things, sets forth the terms on which the collateral agent will receive, hold, administer, maintain, enforce and distribute the proceeds of all liens upon any property of the Issuers and the Guarantors at any time held by it, for the benefit of the current and future holders of First Lien Obligations and Junior Lien Obligations (each as defined in the Collateral Agency Agreement) as well as establishing the priority of the liens on the collateral as between the First Lien Obligations and Junior Lien Obligations.
11. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be estimated, we record a liability at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.
Non-Income Tax and Related Claims. We have received assessments related to, or otherwise have exposure to, non-income tax items such as sales-and-use tax, value-added tax, ad valorem tax, custom duties, and other similar taxes in various taxing jurisdictions. We have determined that we have a probable loss for certain of these taxes and the related penalties and interest and, accordingly, have recorded a $12.7 million and $12.4 million liability at December 31, 2023 and 2022, respectively. We intend to defend these matters vigorously; however, the ultimate outcome of these assessments and exposures could result in additional taxes, interest and penalties for which the fully assessed amounts would have a material adverse effect on our financial condition, results of operations or cash flows.
Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. In the opinion of our management, no such pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Personal Injury Claims. Under our current insurance policies, we self-insure $1.0 million to $5.0 million per occurrence, depending on jurisdiction, with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability in the U.S. Gulf of Mexico. Depending on the nature, severity and frequency of claims that might arise during a policy year, if the aggregate level of claims exceed certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence. For personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico, we self-insure $10.0 million for the first occurrence and, if the aggregate level of claims exceed certain thresholds, we self-insure up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.
The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2023, our estimated liability for personal injury claims was $14.6 million, of which $7.4 million and $7.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2022, our estimated liability for personal injury claims was $18.3 million, of which $3.7 million and $14.6 million were recorded in
“Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
•the severity of personal injuries claimed;
•significant changes in the volume of personal injury claims;
•the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
•inconsistent court decisions; and
•the risks and lack of predictability inherent in personal injury litigation.
Purchase Obligations. At December 31, 2023, we had no purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.
Services Agreement. In February 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly named Baker Hughes, a GE company) (or Baker Hughes) to provide services with respect to certain blowout preventer and related well control equipment (or Well Control Equipment) on our drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. Future commitments under the contractual services agreements are estimated to be approximately $26.4 million annually. Total future commitments are projected to be $96.2 million in the aggregate over the remaining term of the agreement, including a $37.0 million commitment for the purchase of consumables and capital spare parts owned and controlled by the vendor at the end of the service arrangement.
In addition, we lease Well Control Equipment for our drillships under ten-year finance leases. See Note 12 “Leases and Lease Commitments.”
Letters of Credit and Other. We were contingently liable as of December 31, 2023 in connection with a $1.9 million surety bond associated with a building lease that had been issued on our behalf. The letter of credit collateralizing this bond was issued under our revolving credit facility and cannot require collateral except in events of default.
12. 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, onshore storage yards and certain rig equipment and tools. We also lease Well Control Equipment under finance leases. Our leases have original terms ranging from one month to ten years, some of which include options to extend the lease for up to five years and/or to terminate the lease within one year.
We are participants in four sale and leaseback arrangements with a subsidiary of Baker Hughes pursuant to the 2016 sale of Well Control Equipment on our drillships and corresponding agreements to lease back that equipment under ten-year finance leases for approximately $26.0 million per year in the aggregate with renewal options for two successive five-year periods. At inception, these leases were determined to be operating leases. On March 31, 2021, we signed an amendment to the operating lease agreement for the Well Control Equipment. 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, whereby we were required to reassess lease classification and remeasure the corresponding right-of-use (or ROU) asset and lease liability. Due to the purchase option ceiling provision included in the amendment, we now believe that we are reasonably certain to exercise the purchase option at the end of the original lease term. Therefore, we have changed the lease classification from an operating lease to a finance lease and remeasured the ROU asset and lease liability to include the estimated purchase option price of the Well Control Equipment.
In applying ASU 2016-02, we utilize an exemption for short-term leases whereby we do not record leases with terms of one year or less on the balance sheet. We have also made an accounting policy election not to separate lease components from non-lease components for each of our classes of underlying assets, except for subsea equipment,
which includes the Well Control Equipment discussed above. At inception, the consideration for the overall Well Control Equipment arrangement was allocated between the lease and service components based on an estimation of stand-alone selling price of each component, which maximized observable inputs. The costs associated with the service portion of the agreement are accounted for separately from the cost attributable to the equipment leases based on that allocation and thus, are not included in our ROU asset or lease liability balances. The non-lease components for each of our other classes of assets generally relate to maintenance, monitoring and security services and are not separated from their respective lease components. See Note 11 “Commitments and Contingencies.”
The lease term used for calculating our ROU assets and lease liabilities is determined by considering the noncancelable lease term, as well as any extension options that we are reasonably certain to exercise. The determination to include option periods is generally made by considering the activity in the region or for the rig corresponding to the respective lease, among other contract-based and market-based factors. We have used our incremental borrowing rate to discount future lease payments as the rate implicit in our leases is not readily determinable. The incremental borrowing rate was determined primarily based on secured borrowing rates negotiated in relation to our new debt and existing revolving credit facility.
Amounts recognized in our Consolidated Balance Sheets for both our operating and finance leases are as follows (in thousands):
December 31,
Operating Leases:
Other assets
$
37,876
$
30,332
Accrued liabilities
(8,436
)
(13,480
)
Other liabilities
(29,438
)
(16,542
)
Finance Leases:
Drilling and other property and equipment, net of accumulated depreciation
128,303
145,510
Current finance lease liabilities
(15,960
)
(16,965
)
Noncurrent finance lease liabilities
(113,201
)
(131,393
)
Components of lease expense are as follows (in thousands):
Successor
Predecessor
Year Ended
December 31,
Period from
Period from
April 24, 2021 through
January 1, 2021 through
December 21, 2021
April 23, 2021
Operating lease cost
$
15,712
$
19,479
$
11,754
$
11,799
Finance lease cost:
Amortization of ROU assets
17,207
17,207
11,854
-
Interest on lease liabilities
9,315
10,415
7,796
-
Short-term lease cost
Variable lease cost (1)
107,848
12,804
1,237
Total lease cost
$
150,183
$
60,147
$
32,840
$
12,498
(1)Includes charter expenses incurred post-commencement of drilling operations for the managed rigs.
Supplemental information related to leases is as follows (in thousands, except weighted-average data):
Successor
Predecessor
Year Ended
December 31,
Period from
Period from
April 24, 2021 through
January 1, 2021 through
Operating Leases:
December 31. 2021
April 23, 2021
Operating cash flows used
$
15,014
$
19,031
$
12,005
$
10,817
ROU assets obtained in exchange for lease liabilities
21,027
8,662
19,064
1,076
Weighted-average remaining lease term (1)
4.6 years
4.0 years
4.4 years
5.9 years
Weighted-average discount rate (1)
%
%
%
6.89
%
Finance Leases:
Operating cash flows used
$
9,315
$
10,415
$
7,796
$
-
Financing cash flows used
16,965
15,865
9,845
-
ROU assets obtained in exchange for lease liabilities
-
-
174,571
-
Weighted-average remaining lease term (1)
2.5 years
3.5 years
4.5 years
n/a
Weighted-average discount rate (1)
%
%
%
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, 2023 are as follows (in thousands):
Operating Leases
Finance Leases
Total
$
11,181
$
26,352
$
37,533
9,658
26,280
35,938
9,386
94,198
103,584
8,566
-
8,566
4,771
-
4,771
Thereafter
2,788
-
2,788
Total lease payments
$
46,350
$
146,830
$
193,180
Less: Interest
(8,476
)
(17,669
)
(26,145
)
Total lease liability
$
37,874
$
129,161
$
167,035
13. Income Taxes
In April 2021, we reorganized under Chapter 11 of the U.S. Bankruptcy Code in a transaction treated as a tax free reorganization under section 368(a)(1)(G) of the Internal Revenue Code of 1986, as amended (or the IRC). We realized approximately $1.3 billion of cancellation of indebtedness (or COD) income for U.S. tax purposes in 2021. Under exceptions applying to COD income resulting from a bankruptcy reorganization, we were not required to recognize this COD income currently as taxable income. Instead, our tax attribute carryforwards, including net operating losses, other noncurrent assets and the stock of our foreign corporate subsidiaries, were reduced under the operative tax statute and applicable regulations, affecting the balance of deferred taxes where appropriate. The total reduction of tax attributes under these rules amounted to approximately $1.3 billion, which impacted net operating losses and, without giving rise to deferred tax consequences, reduced the tax basis of foreign subsidiaries’ stock. The tax attribute reduction occurs on the first day of a company's tax year following the tax year in which COD income was realized, or, in our case, January 1, 2022.
In the event of a change in ownership, IRC sections 382 and 383 provide an annual limitation with respect to a corporation’s ability to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. Our emergence from the Chapter 11 Cases resulted in a change in ownership for purposes of IRC section 382. The limitation under the IRC is based on the value of the company as of the emergence date.
To achieve business and administrative efficiencies, we undertook an internal restructuring in conjunction with emergence from bankruptcy, resulting in realignment of substantially all our assets and operations under a wholly owned foreign subsidiary, DFAC. In December 2023, we organized a new subsidiary, Diamond Offshore (Switzerland) GmbH (or DOSG), under the laws of Switzerland and DOSG acquired all the issued and outstanding DFAC shares. Effective December 31, 2023, DOSG now owns directly or indirectly all the shares of various foreign subsidiaries that own and operate our fleet of rigs. Our management has determined that we will permanently reinvest foreign earnings of foreign subsidiaries. The potential unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate at December 31, 2023.
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.
The components of income tax (benefit) expense are as follows (in thousands):
Successor
Predecessor
Year Ended
December 31,
Period from
Period from
April 24, 2021 through
January 1, 2021 through
December 31, 2021
April 23, 2021
Federal - current
$
8,375
$
1,267
$
3,645
$
State - current
-
-
Foreign - current
27,215
(4,151
)
1,491
(3,681
)
Total current
35,600
(2,874
)
5,136
(3,510
)
Federal - deferred
6,580
4,538
(6,742
)
(30,955
)
Foreign - deferred
(11,197
)
(4,059
)
3,260
(4,939
)
Total deferred
(4,617
)
(3,482
)
(35,894
)
Total
$
30,983
$
(2,395
)
$
1,654
$
(39,404
)
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
Year Ended
December 31,
Period from
Period from
April 24, 2021 through
January 1, 2021 through
December 31, 2021
April 23, 2021
(Loss) income before income tax expense:
U.S.
$
$
(7,054
)
$
(1,048
)
$
686,202
Foreign
(14,166
)
(98,552
)
(174,642
)
(2,687,595
)
$
(13,723
)
$
(105,606
)
$
(175,690
)
$
(2,001,393
)
Expected income tax benefit at federal statutory rate
$
(2,882
)
$
(22,177
)
$
(36,895
)
$
(420,292
)
Withholding taxes
$
-
-
-
Effect of tax rate changes
-
-
9,871
-
Reorganization items
-
-
(225,563
)
Post-petition interest expense
-
-
-
(6,771
)
Disallowed officers' compensation and restricted stock unit awards
(459
)
2,205
-
-
Interest and penalties reported as income tax expense
3,318
-
-
Effect of foreign operations
32,384
12,639
79,600
163,236
Valuation allowance
(20,527
)
(23,135
)
(45,919
)
515,421
Uncertain tax positions, settlements and adjustments relating to prior years
21,039
25,692
(7,220
)
(67,626
)
Other
(937
)
1,951
2,191
Income tax (benefit) expense
$
30,983
$
(2,395
)
$
1,654
$
(39,404
)
Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows (in thousands):
December 31,
Deferred tax assets:
Net operating loss carryforwards, or NOLs
$
252,732
$
412,152
Foreign tax credits
28,769
27,223
Disallowed interest deduction
66,632
69,604
Worker’s compensation and other current accruals
5,808
6,273
Deferred deductions
7,078
7,661
Deferred revenue
1,467
Operating lease liability
19,744
22,011
Property, plant and equipment
332,981
129,938
Other
5,617
7,234
Total deferred tax assets
720,828
682,129
Valuation allowance
(629,665
)
(650,193
)
Net deferred tax assets
91,163
31,936
Deferred tax liabilities:
Right-of-use assets
(18,964
)
(21,374
)
'Property, plant and equipment
(56,409
)
Other
(1,197
)
(652
)
Total deferred tax liabilities
(76,570
)
(22,026
)
Net deferred tax asset
$
14,593
$
9,910
Net Operating Loss Carryforwards. As of December 31, 2023, we recorded a deferred tax asset of $252.7 million for the benefit of NOL carryforwards, comprised of $57.7 million related to our U.S. losses and $195.0 million related to our international operations. Approximately $139.1 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $273.0 million relates to NOL carryforwards in several foreign jurisdictions, as well as in the U.S. Unless utilized, these NOL carryforwards will expire between 2024 and 2037. As a result of our emergence from bankruptcy, we have significant limitations on our ability to utilize certain U.S. deferred tax assets.
Foreign Tax Credits. As of December 31, 2023, we recorded a deferred tax asset of $28.7 million for the benefit of foreign tax credits in the U.S. Of this balance, $2.6 million relates to a foreign tax credit carryback, which is expected to generate a cash tax benefit. The remaining credits will expire, unless utilized, between 2023 and 2028.
Valuation Allowances. We record a valuation allowance on a portion of our deferred tax assets not expected to be ultimately realized. In determining the need for a valuation allowance, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets.
As of December 31, 2022, valuation allowances aggregating $629.7 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 roll forward of the beginning and ending amount of unrecognized tax benefits, excluding interest and penalties, is as follows (in thousands):
Successor
Predecessor
Year Ended
December 31,
For the Period
For the Period
April 24, 2021
January 1, 2021
through
through
December 31, 2021
April 23, 2021
Balance, beginning of period
$
(21,540
)
$
(21,148
)
$
(26,678
)
$
(214,626
)
Additions for current year tax positions
(7,391
)
(5,993
)
(3,553
)
-
Additions for prior year tax positions
(705
)
(504
)
(1,424
)
(1,282
)
Reductions for prior year tax positions
1,141
4,345
1,730
187,389
Reductions related to statute of limitation expirations
3,878
1,760
8,777
1,841
Reductions related to settlements with taxing authorities
-
-
-
Balance, end of period
$
(24,565
)
$
(21,540
)
$
(21,148
)
$
(26,678
)
The $7.4 million addition for current year uncertain tax positions recorded in the year ended December 31, 2023 was attributable principally to transfer pricing for certain related party transactions. The $1.1 million reduction of uncertain tax positions recorded in the year ended December 31, 2023, principally reflected the strengthening of the U.S. dollar relative to foreign currencies. The $3.9 million reduction of uncertain tax positions recorded in the year ended December 31, 2023 was due to the expiry of applicable statutes of limitation for tax returns filed between 2007 and 2019 in several jurisdictions. The $6.0 million addition for current year uncertain tax positions recorded in the year ended December 31, 2022 was attributable principally to transfer pricing for certain related party transactions. The $4.3 million reduction of uncertain tax positions recorded in the year ended December 31, 2022, principally reflected the strengthening of the U.S. dollar relative to foreign currencies.
At December 31, 2023, $2.2 million and $46.4 million of the net liability for uncertain tax positions were reflected in “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2022, $0.2 million, $1.5 million and $34.7 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. 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 Sheets. Of the net unrecognized tax benefits at December 31, 2023, 2022, and 2021,$48.6 million, $36.0 million and $48.9 million, respectively, would affect the effective tax rates if recognized.
At December 31, 2023, the amount of accrued interest and penalties related to uncertain tax positions was $2.1 million and $25.0 million, respectively. At December 31, 2022, the amount of accrued interest and penalties related to uncertain tax positions was $3.1 million and $12.6 million, respectively.
Interest expense (benefit) recognized during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 related to uncertain tax positions was $0.8 million, $0.9 million, $1.8 million and $0.1 million, respectively. Penalties recognized during the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 related to uncertain tax positions were $16.6 million, $1.0 million, $0.04 million and $(0.4) million, respectively. Of the total 2023 penalties, $16.4 million relates to a 2023 Egyptian court ruling against us for an additional tax assessment on income for taxable years 2006 through 2008. We expect the statute of limitations for the 2014 tax year to expire in 2024 for our subsidiary operating in Romania. We anticipate that the related unrecognized tax benefit will decrease by $0.7 million at that time.
Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. We remain subject to examination by these jurisdictions or are contesting assessments raised upon examinations in respect to the year 2000 and the years 2006 to 2023. We are currently under examination or contesting assessments in Brazil, Egypt, Equatorial Guinea, Malaysia, Romania, and
Trinidad and Tobago. In June 2023, we recorded an uncertain tax liability of $17.7 million related to an assessment by Egypt’s tax authorities for tax years 2006 through 2008. In January 2024, we received notice that Trinidad and Tobago’s tax authority had rejected our administrative appeal of an assessment for taxable year 2015. We intend to bring an action in the Tax Appeal Board seeking annulment of the assessment and have not recorded any reserve related to this disputed assessment.
14. Employee Benefit Plans
Defined Contribution Plans
We maintain defined contribution retirement plans for our U.S., U.K., and third-country national (or TCN) employees.
The plan for our U.S. employees (or the 401k Plan) is designed to qualify under Section 401(k) of the IRC. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. Under the 401k Plan, the employer may elect to match a percentage of each employee's qualifying annual compensation contributed to the 401k Plan on a pre-tax or Roth elective deferral basis. Participants are fully vested in any employer match immediately upon enrollment in the 401k Plan.
During 2023, we matched 100% of the first 4% of each employee's qualifying annual compensation contributed to the 401k Plan and, in 2022, matched 50% of the first 6% of each employee's qualifying annual compensation contributed to the plan. Our provision for contributions was $5.4 million and $3.2 million for the Successor years ended December 31, 2023 and 2022, respectively. There was no provision for contributions to the 401k Plan for the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, as contributions to the plan were suspended effective November 2020 and did not resume until 2022.
The defined contribution retirement plan for our U.K. employees provides that we make annual contributions in an amount equal to the employee's contributions to the plan, generally up to a maximum percentage of the employee's defined compensation per year. Our contributions during 2023, 2022 and 2021 for employees working in the U.K. sector of the North Sea was 5.25%, 4% and 4%, respectively, of the employee's defined compensation. Our provision for contributions was $1.8 million, $0.9 million, $0.6 million and $0.3 million for the Successor periods for the years ended December 31, 2023 and 2022 and from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, respectively.
The defined contribution retirement plan for our TCN employees (or the International Savings Plan) is similar to the 401k Plan. During 2023, we matched 100% of the first 4% of each employee's qualifying annual compensation contributed to the International Savings Plan, and in 2022 matched 50% of the first 6% of each employee's qualifying annual compensation contributed to the plan. Our provision for contributions was $0.1 million and $0.1 million for the Successor years ended December 31, 2023 and 2022, respectively. There was no provision for contributions to the International Savings Plan for the Successor period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021, as contributions to the plan were suspended effective November 2020 and did not resume until 2022.
Deferred Compensation and Supplemental Executive Retirement Plan
Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of the applicable percentage of the base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. We ceased matching contributions to the Supplemental Plan effective January 2020.
15. Segments and Geographic Area Analysis
We provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations. However, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue-earning process as it relates to the offshore drilling industry over the operating lives of our drilling rigs and other qualitative factors such as (i) the nature of services provided (contract drilling), (ii) similarity in operations (interchangeable rig crews and shared management and marketing, engineering, marine and maintenance support), (iii) similar regulatory environment (depending on customer and/or location) and (iv) similar contractual arrangements with customers.
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At December 31, 2023, our active drilling rigs were located offshore four countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.
The following tables provide information about disaggregated revenue by equipment-type and country (in thousands):
Successor
Year Ended December 31, 2023
Total
Contract
Drilling
Revenues
Revenues
Related to
Reimbursable
Expenses
Total
United States
$
513,226
$
36,645
$
549,871
Senegal
169,223
11,586
180,809
United Kingdom
168,894
14,708
183,602
Australia
67,846
9,257
77,103
Brazil
64,794
-
64,794
Total
$
983,983
$
72,196
$
1,056,179
Successor
Year Ended December 31, 2022
Total
Contract
Drilling
Revenues
Revenues
Related to
Reimbursable
Expenses
Total
United States
$
322,021
$
75,069
$
397,090
Senegal
154,574
11,929
166,503
United Kingdom
66,116
8,478
74,594
Australia
92,939
14,082
107,021
Brazil
80,185
-
80,185
Myanmar
8,909
6,976
15,885
Total
$
724,744
$
116,534
$
841,278
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
Senegal
48,758
10,110
58,868
United Kingdom
55,245
3,859
59,104
Australia
95,601
15,132
110,733
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
United Kingdom
27,967
2,300
30,267
Australia
17,031
4,697
21,728
Brazil
3,421
-
3,421
Myanmar
11,730
1,970
13,700
Total
$
153,364
$
16,015
$
169,379
The following table presents the locations of our long-lived tangible assets by country as of December 31, 2023, 2022 and 2021. 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).
December 31,
Drilling and other property and equipment, net:
United States
$
543,930
$
362,813
$
559,288
International:
United Kingdom
251,049
256,837
98,338
Senegal
169,627
352,655
188,694
Australia
98,793
91,089
106,173
Brazil
86,057
69,596
76,383
Spain (1)
-
-
142,930
Other countries (2)
6,912
8,918
4,089
612,438
779,095
616,607
Total
$
1,156,368
$
1,141,908
$
1,175,895
(1)The Ocean GreatWhite was relocated to the U.K. in 2022 for reactivation and contract preparation activities.
(2)Countries with long-lived assets that individually comprise less than 5% of total drilling and other property and equipment, net of accumulated depreciation.
Major Customers
Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the Successor periods for the years ended December 31, 2023 and 2022 and the period from April 24, 2021 through December 31, 2021 and the Predecessor period from January 1, 2021 through April 23, 2021 that contributed more than 10% of our total revenues are as follows:
Successor
Predecessor
Year Ended
Period from
Period from
December 31,
April 24, 2021 through
January 1, 2021 through
2023 (1)
2022 (1)
December 31, 2021 (1)
April 23, 2021
BP
48.4
%
33.1
%
25.4
%
39.8
%
Woodside
21.5
%
29.7
%
22.4
%
0.5
%
Oxy
2.9
%
3.9
%
11.5
%
21.4
%

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

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to ensure information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.
Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2023. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2023.
Internal Control Over Financial Reporting
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error or mistakes, faulty judgments in decision-making and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2023. 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, 2023, 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 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
During the quarter ended December 31, 2023, none of our directors or officers (as defined in Exchange Act Rule 16a-1(f)) adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” in each case as such terms are defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance.
Information about our executive officers is reported under the caption “Information About Our Executive Officers” in Item 1 of Part I of this report.
Additional information required by this item can be found in our Proxy Statement for our Annual Meeting of Stockholders to be filed with the SEC within 120 days after December 31, 2023 (or 2024 Proxy Statement) and is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
Information required by this item can be found in our 2024 Proxy Statement and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information required by this item can be found in our 2024 Proxy Statement and is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required by this item can be found in our 2024 Proxy Statement and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services.
Information required by this item can be found in our 2024 Proxy Statement and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
(a)Index to Financial Statements and Financial Statement Schedules
(1) Financial Statements
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID 00034)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income or Loss
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(b)Exhibits
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
Fourth 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 May 10, 2023).
3.2
Third Amended and Restated Bylaws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on February 10, 2023).
4.1
Indenture, dated September 21, 2023, by and among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, Diamond Finance, LLC, the other Guarantors party thereto, and HSBC Bank USA, National Association, as trustee and as collateral agent, relating to the 8.500% Senior Secured Second Lien Notes due 2030 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on September 22, 2023).
4.2*
Description of Diamond Offshore Drilling, Inc.'s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.
10.1
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).
10.2
Amendment No. 1 to Credit Agreement, dated as of March 24, 2023, by and among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, the other guarantors party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on March 30, 2023).
10.3**
Amendment No. 2 to Credit Agreement, dated September 12, 2023, by and among Diamond Foreign Asset Company, Diamond Offshore Drilling, Inc., HSBC Bank USA, National Association, as administrative agent and as collateral agent, and the lenders and issuing lenders from time to time party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on September 13, 2023).
10.4
Agency Assignment Agreement and Master Assignment of Liens, dated as of August 10, 2023, by and among HSBC Bank USA, National Association, as successor administrative agent and collateral agent,
Wells Fargo Bank, National Association, as resigning administrative agent and collateral agent, Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, the other loan parties named therein, the Revolving Credit Agreement lenders party thereto, and the Term Loan Agreement lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on August 11, 2023).
10.5
Amended and Restated Collateral Agency and Intercreditor Agreement, dated September 21, 2023, by and among Diamond Foreign Asset Company, Diamond Offshore Drilling, Inc., other grantors from time to time party thereto and HSBC Bank USA, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on September 22, 2023).
10.6
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).
10.7
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).
10.8+
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).
10.9+
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).
10.10+
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).
10.11+
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).
10.12+
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).
10.13+
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).
10.14+
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).
10.15+
Supplemental Severance Plan (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on September 3, 2021).
10.16+
Specimen Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on May 11, 2022).
10.17+
Specimen Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on May 11, 2022).
10.18+
The Diamond Offshore Drilling, Inc. Short-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on April 28, 2023).
10.19+
Form of 2022 Short-Term Incentive Plan Participation Letter (incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K filed on February 28, 2023).
10.20+
Form of 2023 Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.21 to our Annual Report on Form 10-K filed on February 28, 2023).
10.21+
Form of 2023 Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.22 to our Annual Report on Form 10-K filed on February 28, 2023).
10.22+
Form of Non-Employee Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.23 to our Annual Report on Form 10-K filed on February 28, 2023).
10.23+*
Form of 2024 Time-Vesting Restricted Stock Unit Award Agreement.
10.24+*
Form of 2024 Executive Performance-Vesting Restricted Stock Unit Award Agreement.
21.1*
List of Subsidiaries of Diamond Offshore Drilling, Inc.
23.1*
Consent of Deloitte & Touche LLP.
24.1
Power of Attorney (set forth on the signature page hereof).
31.1*
Rule 13a-14(a) Certification of the Chief Executive Officer.
31.2*
Rule 13a-14(a) Certification of the Chief Financial Officer.
32.1*
Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.
97.1*
Incentive Compensation Recoupment Policy
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 With Embedded Linkbase Documents.
104*
The cover page of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, formatted in Inline XBRL (included with the Exhibit 101 attachments).
* Filed or furnished herewith.
** Certain schedules and similar attachments have been omitted. The Company agrees to furnish a supplemental copy of any omitted schedule or attachment to the Securities and Exchange Commission upon request.
+ Management contracts or compensatory plans or arrangements.