# Noble Corp plc (NE) FY 2023 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Noble Corp plc's 10-K for fiscal year 2023.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1895262/000162828024006622/ne-20231231.htm
Accession: 0001628280-24-006622
Filing date: 2024-02-23
Report date: 2023-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/NE/
All MD&A years: /company/NE/mda/
Previous year: /company/NE/mda/fy2022/ (FY 2022)
Next year: /company/NE/mda/fy2024/ (FY 2024)

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

The following discussion is intended to assist you in understanding our financial position at December 31, 2023 and 2022, and our results of operations for the years ended December 31, 2023 and 2022, the period from February 6 through December 31, 2021, and the period from January 1 through February 5, 2021.

The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed by Noble.

Executive Overview

Noble is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. Our business strategy is centered around providing efficient, reliable, and safe offshore drilling services to our customers. We have one of the youngest and highest specification fleets of global scale in the industry, with diversification across asset classes, geographic regions, and customers. The Company has a track record of industry-leading utilization coupled with a commitment to best-in-class safety performance and customer satisfaction. We strive to be a leader in industry innovation and first-mover in sustainability.

Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components prepared to execute our customers’ complicated offshore drilling programs safely and with greater efficiency. We are primarily focused on the ultra-deepwater market and the harsh and ultra-harsh environment jackup markets, which typically are more technically challenging markets in which to operate.

We emphasize safe operations, environmental stewardship, and superior performance through a structured management system, the employment of qualified and well-trained crews and onshore support staff, the care of our surroundings and the neighboring communities where we operate, and other activities advancing our environmental sustainability, social responsibility, and good governance. We also manage rig operating costs through the implementation and continuous improvement of innovative systems and processes, which includes the use of data analytics and predictive maintenance technology.

As of the filing date of this Annual Report on Form 10-K, our fleet of 32 drilling rigs consists of 19 floaters and 13 jackups strategically deployed worldwide. We typically employ each drilling unit under an individual contract, and many contracts are awarded based upon a competitive bidding process.

We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent, and government-owned or controlled oil and gas companies throughout the world.

For the year ended December 31, 2023, our financial and operating results include:

•operating revenues totaling $2.6 billion;

•net income of $481.9 million or $3.32 per diluted share;

•net cash provided by operating activities totaling $574.3 million;

•nothing drawn down on the 2023 Revolving Credit Facility as of December 31, 2023, and

•a year end cash balance of $360.8 million.

Demand for our services is driven by the offshore exploration and development programs of oil and gas operators, which in turn are influenced by many factors. Those factors include, but are not limited to, the price and price stability of oil and gas, the relative cost and carbon footprint of offshore resources within each operator’s broader energy portfolio, global macroeconomic conditions, world energy demand, the operator’s strategy toward renewable energy sources, environmental considerations, and governmental policies.

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Over the last decade, the offshore drilling industry has experienced significant volatility and change, which has meaningfully impacted both the supply of, and demand for, offshore rigs. After several years of a significantly oversupplied rig market, industry conditions had started to gradually improve in 2019, which was evidenced by increasing utilization and improving dayrates. However, in the first half of 2020, this gradual recovery was abruptly halted as oil prices experienced concurrent supply and demand shocks that were the result of disagreements among OPEC+ members and the global COVID-19 pandemic, respectively. This had a negative impact on both utilization and dayrates for the offshore drilling industry and led to further financial challenges for many drilling and other service companies. However, by early 2021, oil prices returned to pre-pandemic levels and continued to rise throughout 2021.

Since 2021, oil prices generally remained at levels that were supportive of offshore exploration and development activity. While the ongoing Russia-Ukraine conflict and related sanctions, inflationary pressures and the subsequent government and central bank efforts to curb inflation, recession concerns, and supply chain disruptions did create some uncertainty relating to future global energy demand, global rig demand has increased since 2021.

This increase in global demand has been the result of the combination of growing confidence in commodity prices remaining at or above current levels, heightened focus on energy security, recent multi-year underinvestment in the development and exploration of hydrocarbons, and relative attractiveness of offshore plays with respect to both cost and a carbon emissions perspective. This had a positive impact on both utilization and day rates for certain of our rig classes.

Outlook

In recent years, oil prices have generally remained at levels that are supportive of offshore exploration and development activity and global rig demand is increasing. This increasing demand has been caused by the combination of growing confidence in commodity prices, heightened focus on energy security, recent multi-year underinvestment in the development and exploration of hydrocarbons, and relative attractiveness of offshore plays with respect to both cost and carbon emissions. This increase had a positive impact on dayrates for certain of our rig classes.

The global rig supply has come down from historic highs as Noble and other offshore drilling contractors have retired less capable and idle assets. Concurrently, the incoming supply of newbuild offshore drilling rigs has diminished materially, with several newbuild rigs stranded in shipyards. However, we expect many of these stranded newbuild rigs may continue to make their way into the global market over the next few years.

Although the market outlook in our business varies by geographical region and water depth, we remain encouraged by the outlook in the ultra-deepwater floater market, with overall demand having increased from 2020 lows. Our customers continue to focus on the highest specification floaters, which represents the majority of our floater fleet. We have also observed an overall demand increase in the global jackup market, with the Middle East being the largest component of this increase. While we remain encouraged about the increasing overall rig demand, to the extent global macroeconomic concerns become more prevalent and produce downward pressure on oil and gas prices, we could experience downward pressure on overall rig demand for both floaters and jackups.

As of the date of this report, the majority of our jackup fleet is positioned in the North Sea. While we are starting to see some increased tender activity in the UK North Sea, overall activity levels in this region remain subdued compared to historical levels. The Norway ultra-harsh environment jackup market is similar, where current activity also remains below historical levels, despite the market being attractive to operators given it is characterized by low-cost and low-emission barrels.

While the length of contract terms has started to moderately increase, the overall market remains characterized by generally shorter-term contracts. This leads to an increased number of rig contract start-ups, both with different customers and among different regions. These rig contract start-ups and other shipyard projects may result in incremental resources and costs and, in certain cases, may delay delivery of the applicable rig which may trigger applicable late delivery clauses. The Noble Faye Kozak, currently undergoing a rig contract start-up, is delayed and currently expected to commence in early third quarter 2024 . Additionally, shorter-term contracts have resulted in, and is likely to continue to result in, lower overall utilization for our fleet driven by more idle time between contracts.

The energy transition from hydrocarbons to renewables poses a challenge to the oil and gas sector and our market. Energy rebalancing trends have accelerated in recent years as evidenced by promulgated or proposed government policies and commitments by many of our customers to further invest in sustainable energy sources. Our industry could be further challenged as our customers rebalance their capital investments more towards alternative energy sources. However, at the same time, there continues to be a global dependence on the combustion of hydrocarbons to provide reliable and affordable energy. Low-cost and low-emission barrels are expected to be the most attractive conventional source to meet

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energy needs, both currently and in the future. Global energy demand is predicted to increase over the coming decades, and we expect that offshore oil and gas will continue to play an important and lasting role in meeting this demand.

We expect inflationary pressures to persist, which has led or may lead to increased costs of services. Additionally, we expect supply chain disruptions to continue, and potentially accelerate, as geopolitical crises, such as the Russia-Ukraine conflict, Middle East conflicts, and the Guyana-Venezuela dispute, and their respective regional and global ramifications, have the potential to negatively impact our ability to conduct our day-to-day operations.

Contract Drilling Services Backlog

We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2023, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts. As of December 31, 2023, contract drilling services backlog totaled approximately $4.8 billion, which represents approximately 65% of available days for 2024.

We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and include certain assumptions based on the terms of certain contractual arrangements, discussed in the notes to the table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization, and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers, or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.

The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

[[GREPCENT_TABLE]]
[["","","","","Year Ending December 31, (1)"],["","","Total","","2024","","2025","","2026","","2027"],["","","(In thousands)"],["Contract Drilling Services Backlog"],["Floaters (2) (3)","","$3,708,272","","$1,745,695","","$991,472","","$715,577","","$255,528"],["Jackups (4)","","1,116,860","","465,463","","269,159","","205,598","","176,640"],["Total","","$4,825,132","","$2,211,158","","$1,260,631","","$921,175","","$432,168"],["Percent of Available Days Committed (5)"],["Floaters","","","","61","%","","34","%","","24","%","","9","%"],["Jackups","","","","70","%","","32","%","","18","%","","14","%"],["Total","","","","65","%","","33","%","","22","%","","11","%"]]
[[/GREPCENT_TABLE]]

(1)Represents a twelve-month period beginning January 1. Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.

(2)One of our long-term drilling contracts with Shell plc, the Noble Globetrotter II, contains a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. The contract now has a contractual dayrate floor of $275,000 per day. The dayrate for this rig will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism.

(3)Noble entered into a multi-year Commercial Enabling Agreement (the “CEA”) with ExxonMobil in February 2020. Under the CEA, dayrates earned by each rig will be updated twice per year to the projected market rate at the time the new rate goes into effect, subject to a scale-based discount and a performance bonus that appropriately aligns the interests of Noble and ExxonMobil. Under the CEA, the table above includes awarded and remaining term of three years and five months related to each of the four following rigs: the Noble Tom Madden, Noble Bob Douglas, Noble Don Taylor, and Noble Sam Croft. Under the CEA, ExxonMobil may reassign terms among rigs.

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(4)In 2022, Noble renewed its five-year Framework Agreement with Aker BP for the provision of ultra-harsh environment jackup rigs, the Noble Integrator and Noble Invincible, for activities offshore Norway. Under the Framework Agreement, different rate structures apply reflecting different operating modes, agreed incentive schemes, and adjustments for operating expenses. Rate structures are adjusted annually to reflect market conditions.

(5)Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs, including cold-stacked rigs, and the number of calendar days in such period.

The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates, and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors—Risks Related to Our Business and Operations—Our current backlog of contract drilling revenue may not be ultimately realized.”

As of December 31, 2023, ExxonMobil, Aker BP, and Petrobras represented approximately 42.5%, 15.3%, and 12.9% of our backlog, respectively.

Results of Operations

Results for the years ended December 31, 2023 and 2022

Net income for the year ended December 31, 2023, was $481.9 million, or $3.32 per diluted share, on operating revenues of $2.6 billion compared to net income for the year ended December 31, 2022, of $168.9 million, or $1.73 per diluted share, on operating revenues of $1.4 billion.

Key Operating Metrics

Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates, and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “Contract Drilling Services” below.

The following table presents the average rig utilization, operating days, and average dayrates for our rig fleet for the periods indicated.

[[GREPCENT_TABLE]]
[["","","Average Rig Utilization (1)","","Operating Days (2)","","Average Dayrates (2)"],["","","Year Ended December 31,","","Year Ended December 31,","","Year Ended December 31,"],["","","2023","","2022","","2023","","2022","","2023","","2022"],["Floaters (3)","","73","%","","77","%","","5,067","","","3,654","","","$382,041","","$273,500"],["Jackups (3)","","64","%","","77","%","","3,272","","","2,751","","","128,161","","","119,251"],["Total","","69","%","","77","%","","8,339","","","6,405","","","$282,392","","$207,240"]]
[[/GREPCENT_TABLE]]

(1)We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.

(2)An operating day is defined as a calendar day during which a rig operated under a drilling contract. We define average dayrates as revenue from contract drilling services earned per operating day. Average dayrates have not been adjusted for the non-cash amortization related to favorable and unfavorable customer contract intangibles.

(3)Figures in the table include the rigs acquired in connection with the Business Combination and exclude the five jackup rigs (each a “Remedy Rig,” and collectively the “Remedy Rigs”) sold in October 2022.

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Contract Drilling Services

The following table presents the operating results for our contract drilling services segment for the period indicated (dollars in thousands):

[[GREPCENT_TABLE]]
[["","","Years ended December 31,","","Change"],["","","2023","","2022","","$","","%"],["Operating revenues:"],["Contract drilling services","","$","2,461,715","","","$","1,332,841","","","$","1,128,874","","","85","%"],["Reimbursables and other (1)","","127,303","","","81,006","","","46,297","","","57","%"],["","","$","2,589,018","","","$","1,413,847","","","$","1,175,171","","","83","%"],["Operating costs and expenses:"],["Contract drilling services","","$","1,452,281","","","$","897,096","","","$","555,185","","","62","%"],["Reimbursables (1)","","91,642","","","64,427","","","27,215","","","42","%"],["Depreciation and amortization","","301,345","","","146,879","","","154,466","","","105","%"],["General and administrative","","128,413","","","82,177","","","46,236","","","56","%"],["Merger and integration costs","","60,335","","","84,668","","","(24,333)","","","(29)","%"],["Gain on sale of operating assets, net","","\u2014","","","(90,230)","","","90,230","","","(100)","%"],["Hurricane losses and (recoveries), net","","(19,703)","","","60","","","(19,763)","","","(32,938)","%"],["","","2,014,313","","","1,185,077","","","829,236","","","70","%"],["Operating income (loss)","","$","574,705","","","$","228,770","","","$","345,935","","","151","%"]]
[[/GREPCENT_TABLE]]

(1)We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations, or cash flows.

Contract Drilling Services Revenues

The following table provides information about contract drilling services revenues and costs by rig types (dollars in millions except average dayrates):

[[GREPCENT_TABLE]]
[["","","","Years Ended December 31,"],["","","","2023","","2022"],["","","","Floaters","","Jackups","","Floaters","","Jackups"],["Contract drilling services revenues","","$","2,010","","","$","452","","","$","998","","","$","335"],["Contract drilling services costs","","$","1,112","","","$","340","","","$","600","","","$","297"],["Average rig utilization","","","73","%","","64","%","","77","%","","77","%"],["Operating days","","","5,067","","","3,272","","","3,654","","","2,751"],["Average dayrates","","","$","382,041","","","$","128,161","","","$","273,500","","","$","119,251"],["Total rigs","\u2014 Beginning","","19","","","13","","","12","","","8"],["","\u2014 Acquired","","\u2014","","","\u2014","","","8","","","10"],["","\u2014 Disposed","","\u2014","","","\u2014","","","(1)","","","(5)"],["","\u2014 Ending","","19","","","13","","","19","","","13"]]
[[/GREPCENT_TABLE]]

Floaters. During the year ended December 31, 2023, floaters generated revenue of $2.0 billion, as compared to $997.8 million in year ended December 31, 2022. The increase in revenue was mainly attributable to $581.2 million provided by the eight additional floaters acquired in the Business Combination with Maersk Drilling in October 2022 as well as $360.2 million due to an increase in average dayrates across the remainder of the fleet in the current period. These increases were partly offset by $5.0 million from fewer operating days across the remainder of the fleet in the current period. Additionally, floater revenue from net non-cash amortization related to off-market customer contract assets and liabilities increased $76.0 million in the current period.

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Jackups. During the year ended December 31, 2023, jackups generated revenue of $451.6 million, as compared to $335.0 million in year ended December 31, 2022. The increase in revenue was mainly attributable to $201.4 million provided by the 10 additional jackups acquired in the Business Combination with Maersk Drilling in October 2022 as well as $3.4 million due to an increase in average dayrates across the remainder of the fleet in the current period. These increases were partly offset by $66.8 million pertaining to the divestiture of the Remedy Rigs in October 2022 in connection with the Business Combination with Maersk Drilling and $46.9 million from less operating days across the remainder of the fleet. Additionally, jackups revenue from net non-cash amortization related to off-market customer contract assets and liabilities increased $25.5 million in the current period.

Operating Costs and Expenses

Floaters. During the year ended December 31, 2023, total contract drilling services cost related to floaters was $1.1 billion, as compared to $600.2 million in year ended December 31, 2022. The primary drivers of the increase were $335.0 million related to the eight additional floaters acquired in the Business Combination with Maersk Drilling in October 2022 and $180.6 million in increased crew, repairs and maintenance, and material costs across the remainder of the fleet. These increases were offset by $3.9 million due to the divestiture of a semisubmersible unit late in the first quarter of 2022.

Jackups. During the year ended December 31, 2023, total contract drilling services cost related to jackups was $340.0 million, as compared to $296.9 million in year ended December 31, 2022. The increase was primarily driven by $136.2 million related to the 10 additional jackups acquired in the Business Combination with Maersk Drilling in October 2022. These increases were partially offset by the reduction of $81.5 million in expenses after the sale of the Remedy Rigs in October 2022.

Depreciation and amortization. Depreciation and amortization totaled $301.3 million and $146.9 million during the years ended December 31, 2023 and 2022, respectively. The increase of $154.5 million was primarily due to $132.1 million related to 18 rigs and related equipment acquired in the Business Combination with Maersk Drilling in October 2022. This increase was partially offset by the sale of the Remedy Rigs in October 2022 and the divestiture of a semisubmersible unit in the first quarter of 2022.

General and administrative. General and administrative expenses totaled $128.4 million and $82.2 million during the years ended December 31, 2023 and 2022, respectively. The increase was primarily related to the Business Combination with Maersk Drilling in October 2022 with increases across several categories including employee related costs.

Merger and integration costs. Noble incurred $60.3 million and $84.7 million of merger and integration costs during the years ended December 31, 2023 and 2022, respectively, primarily in connection with the Business Combination with Maersk Drilling in October 2022. Costs primarily related to severance plans and share-based compensation charges, transaction-related acquisition costs, professional fees, and certain integration-related activities that were directly attributable to the Business Combination. During the year ended December 31, 2023, merger and integration costs declined compared to the year ended December 31, 2022, primarily due to decreases in professional fees and severance costs. This decrease was partly offset by an increase in costs and professional fees incurred to integrate systems. For additional information, see “Note 4 — Acquisitions and Divestitures” and “Note 5 — Merger and Integration Costs” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain on sale of operating assets, net. During the year ended December 31, 2022, Noble recognized a gain, net of transaction costs, of $90.2 million in connection with the sale of the Remedy Rigs and the Noble Clyde Boudreaux. For additional information, see “Note 4 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Hurricane losses and recoveries, net. Noble recognized $31.8 million of costs during the year ended December 31, 2023, in connection with the Hurricane Ida incident, which was offset by the recognition of insurance recoveries of $51.5 million. During the year ended December 31, 2022, Noble recognized $22.0 million of costs, which was offset by the recognition of insurance recoveries of $21.9 million. For additional information, see “Note 14 — Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Other Income and Expenses

Interest expense, net of amounts capitalized. Interest expense totaled $59.1 million and $42.7 million for the years ended December 31, 2023 and 2022, respectively. The increase was due to the additional debt assumed in the Business Combination with Maersk Drilling in October 2022, which was refinanced by the issuance of 8.000% Senior Notes in April 2023. For additional information, see “Note 8 — Debt“ to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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Gain (loss) on extinguishment of debt, net. Noble recognized loss on extinguishment of debt of $26.4 million for the year ended December 31, 2023, related to the redemption of the remaining balance on our Second Lien Notes and refinancing of other debt. For additional information, see “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Interest income and other, net. Noble recognized other income of $18.1 million for the year ended December 31, 2023, primarily related to the recognition of approximately $19.1 million of compensation related to a joint taxation scheme with A.P. Møller Holding A/S. For additional information, see “Note 12 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We recognized other income of $14.4 million for the year ended December 31, 2022.

Gain on bargain purchase. Noble recognized a $5.0 million gain on the bargain purchase of Maersk Drilling for the year ended December 31, 2023. For additional information, see “Note 4 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Income tax benefit (provision). Noble recorded an income tax provision of $30.3 million and $22.6 million during the years ended December 31, 2023 and 2022, respectively.

During the year ended December 31, 2023, our tax provision included tax benefits of $187.2 million related to a release of valuation allowances in Luxembourg, Guyana, Switzerland, and Norway, and a tax benefit of $6.8 million related to an uncertain tax position release. Such tax benefits were offset by tax expenses related to uncertain tax positions of $20.9 million in various countries, contract fair value amortization of $23.7 million, and various recurring quarterly accruals of $179.6 million primarily in Guyana, Switzerland, and Luxembourg.

During the year ended December 31, 2022, our tax provision included tax benefits of $42.1 million related to a release of valuation allowance in Guyana and Luxembourg, $1.3 million related primarily to other deferred tax adjustments, and $6.6 million related to a reduction in legacy Maersk tax contingencies primarily due to favorable foreign exchange movements. Such tax benefits were offset by tax expenses of $2.3 million related to the sale of the Remedy Rigs, $10.8 million related to contract fair value amortization, and various recurring items comprised of Guyana excess withholding tax on gross revenue of $34.7 million and annual current and deferred tax expense accrual of $24.9 million primarily in Luxembourg, Switzerland, US, Norway, and Ghana.

2022 Compared to 2021

Information related to a comparison of our results of operations for the year ended December 31, 2022, compared to the period from February 6 through December 31, 2021, (“Prior Year Successor Period”) and the period from January 1 through February 5, 2021, (“Prior Year Predecessor Period”) is included in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, filed with the SEC on March 9, 2023.

Liquidity and Capital Resources

Debt Refinancing

In April 2023, Noble Finance II, LLC (“Noble Finance II”), a wholly owned subsidiary of Noble, issued $600.0 million in aggregate principal amount of its 8.000% Senior Notes due 2030 (“2030 Notes”). The 2030 Notes were issued pursuant to an indenture, dated April 18, 2023, among Noble Finance II, the subsidiaries of Noble Finance II party thereto, as guarantors, and U.S. Bank Trust Company, National Association, as trustee. The net proceeds from the offering of 2030 Notes were primarily used to (i) repay the approximately $347.5 million of outstanding borrowings under the New DNB Credit Facility (as defined below), (ii) redeem (the “Redemption”) the approximately $173.7 million aggregate principal amount of outstanding Second Lien Notes, and (iii) pay any premiums, fees, and expenses related to the Redemption and the issuance of the 2030 Notes. As of December 31, 2023, we had outstanding $600.0 million aggregate principal amount of our 2030 Notes.

Amended and Restated Senior Secured Revolving Credit Agreement

On April 18, 2023, certain subsidiaries of Noble amended and restated the senior secured credit facility, dated February 5, 2021, by entering into an Amended and Restated Senior Secured Revolving Credit Agreement, dated April 18, 2023 (the “2023 Revolving Credit Agreement”), by and among Noble Finance II, Noble International Finance Company (“NIFCO”) and Noble Drilling A/S, as borrowers (the “Borrowers”), the lenders and issuing banks party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and security trustee. The revolving credit facility under the 2023 Revolving Credit Agreement (the “2023 Revolving Credit Facility”) provides for commitments of $550.0 million with

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maturity in April 2028. The guarantors under the 2023 Revolving Credit Facility are the same subsidiaries of Noble Finance II that are or will be guarantors of the 2030 Notes.

As of December 31, 2023, we had no borrowings outstanding and $7.4 million of letters of credit issued under our 2023 Revolving Credit Facility and an additional $108.1 million in letters of credit and surety bonds issued under bilateral arrangements. For additional information about our 2023 Revolving Credit Facility, see “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Second Lien Notes

On the Emergence Effective Date, pursuant to the Backstop Commitment Agreement, dated October 12, 2020, among the Debtors and the backstop parties thereto, Noble Cayman and Finco consummated the Rights Offering of the Second Lien Notes and associated Noble Cayman Shares at an aggregate subscription price of $200.0 million. On April 18, 2023, we redeemed the remaining balance of approximately $173.7 million aggregate principal amount of outstanding Second Lien Notes using a portion of the proceeds from the offering of the 2030 Notes, and recognized a loss of approximately $25.7 million. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Debt Open Market Repurchases

In the third and fourth quarter of 2022, we purchased $42.3 million aggregate principal amount of our Second Lien Notes for approximately $48.1 million, plus accrued interest, as open market repurchases and recognized a loss of approximately $4.6 million.

DNB Credit Facility and New DNB Credit Facility

Upon the Closing Date, Noble guaranteed the Term and Revolving Facilities Agreement dated December 6, 2018, by and among Maersk Drilling, the rig owners and material intragroup charterers party thereto and DNB Bank ASA as agent (as amended from time to time, the “DNB Credit Facility”). On December 22, 2022, the DNB Credit Facility and related Noble guarantee were terminated and, Maersk Drilling, as the borrower, the Company, as parent guarantor, certain subsidiaries of Maersk Drilling as guarantors, and the lenders identified therein, with DNB Bank ASA, New York Branch acting as Agent entered into a new Term Facility Agreement (the “New DNB Credit Facility”). On April 18, 2023, we repaid the $347.5 million of outstanding borrowings under the New DNB Credit Facility using a portion of the proceeds from the offering of the 2030 Notes, and recognized a loss of approximately $0.7 million. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

DSF Credit Facility

The Company guaranteed the Term Loan Facility Agreement dated December 10, 2018, by and between Maersk Drilling and Danmarks Skibskredit A/S as lender, agent, and security agent (as amended from time to time, the “DSF Credit Facility”) in connection with the Business Combination with Maersk Drilling that closed on October 3, 2022. The DSF Credit Facility was repaid in full on February 23, 2023, using cash on hand and the facility is no longer in place as of December 31, 2023. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Sources and Uses of Cash

Our principal sources of capital in 2023 were cash generated from operating activities as well as net proceeds from the issuance of the 2030 Notes. Cash on hand during the current period was primarily used for the following:

•normal recurring operating expenses;

•planned and discretionary capital expenditures;

•repurchase, redemptions, or repayments of debt and interest;

•fees and expenses related to merger and integration costs;

•share repurchases and dividend payments; and

•certain contractual cash obligations and commitments.

Our anticipated cash flow needs, both in the short term and long term, may also include the above.

We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand, proceeds from sales of assets, or borrowings under the 2023 Revolving Credit Facility and we believe this will provide us with sufficient liquidity to fund our cash flow needs over the next 12 months. Subject to market conditions and other factors, we may also issue equity or long-term debt securities to fund our cash flow needs and for other purposes. In 2022 and 2023, we incurred and, in 2024, we anticipate to incur, additional expenses and capital costs related to the damage and repair of a jackup rig. These

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incurred costs exceeded our $5.0 million deductible in 2022. We received partial insurance recoveries in 2023 and we continue to seek insurance recoveries for the remainder of the incurred and anticipated costs.

Net cash provided by operating activities was $574.3 million and $281.0 million for the years ended December 31, 2023 and 2022, respectively. Net cash provided by operating activities increased mainly due to the Business Combination with Maersk Drilling. We had working capital balances of $420.1 million and $384.7 million at December 31, 2023 and 2022, respectively.

Net cash used in investing activities was $366.5 million for the year ended December 31, 2023, and consisted of capital expenditures on routine projects associated with overhauls and upgrades on various rigs in the newly combined fleet. Net cash provided by investing activities was $375.8 million for the year ended December 31, 2022, and included proceeds from the sale of the Remedy Rigs and cash acquired in the Business Combination with Maersk Drilling.

Net cash used in financing activities was $325.8 million and $367.8 million for the years ended December 31, 2023 and 2022, respectively. The year ended December 31, 2023, included the repayment of the DSF Credit Facility in full, using cash on hand, redemption of the remaining balance of the Second Lien Notes, repayment of the DNB Credit Facility, and issuance of 2030 Notes. We also repurchased 2.3 million of our Ordinary Shares for total of $94.8 million and made dividend payments to our shareholders of $98.8 million. During the year ended December 31, 2022, we refinanced part of the assumed debt from the Business Combination, resulting in a net pay down of $277.3 million, and utilized approximately $48.1 million of cash to repurchase $42.3 million aggregate principal amount of our Second Lien Notes, plus accrued interest, as open market repurchases and recognized a loss of approximately $4.6 million. The Compulsory Purchase was completed in the fourth quarter of 2022, at a cost of $69.9 million, paid in DKK and 4.1 million shares issued.

At December 31, 2023, we had a total contract drilling services backlog of approximately $4.8 billion, which includes a commitment of 65% of available days for 2024. For additional information regarding our backlog, see “— Contract Drilling Services Backlog.”

Capital Additions

Capital additions totaled $454.3 million and $193.6 million for the years ended December 31, 2023 and 2022, respectively. Capital additions for the year ended December 31, 2023, consisted of the following:

•$258.9 million for sustaining capital;

•$166.7 million in major projects, including subsea and other related projects; and

•$28.7 million for rebillable capital and contract modifications.

Our total capital additions estimate for 2024, net of reimbursements, is expected to range between $400.0 million and $440.0 million, of which approximately $270.0 million to $300.0 million is currently anticipated to be spent for sustaining capital. We expect to fund these capital additions with cash generated by our operations and cash on hand.

From time to time we consider possible projects and may have certain events that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, while liquidity and preservation of capital remains our top priority, we will continue to evaluate acquisitions of drilling units from time to time.

Dividends

Our most recent quarterly dividend, totaling approximately $56.4 million (or $0.40 per share), was declared on October 31, 2023, and paid on December 14, 2023, to shareholders of record at close of business on November 15, 2023. During the year ended December 31, 2023, we declared dividends of approximately $101.8 million, including accrued dividends, (or $0.70 per share), and made cash dividend payments of approximately $98.8 million.

On February 22, 2024, our Board of Directors approved a declaration of a quarterly cash interim dividend on our Ordinary Shares of $0.40 per share. This dividend is to be payable on March 21, 2024, to shareholders of record at close of business on March 08, 2024.

The declaration and payment of dividends require authorization of the Board of Directors, provided that such dividends on issued share capital may be paid only out of the Company’s “distributable reserves” as determined by reference to relevant statutory accounts in accordance with English law. The Company is not permitted to pay dividends out of share capital, which includes share premiums. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, the availability of sufficient distributable reserves, contractual and indenture restrictions, and other factors deemed relevant by our Board.

Share Repurchases

Under law, the Company is only permitted to purchase its own Ordinary Shares by way of an “off-market purchase” pursuant to a contract approved by shareholders. Such purchases may be paid for only out of Noble’s “distributable

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reserves” as determined by reference to relevant statutory accounts in accordance with law. As of the date of this report, we have shareholder authority to repurchase up to 15% per annum of the issued share capital of the Company as of the beginning of each fiscal year for a five-year period (subject to an overall aggregate maximum of 20,601,161 Ordinary Shares). During the year ended December 31, 2023, we repurchased 2.3 million of our Ordinary Shares, which were subsequently cancelled.

Summary of Contractual Cash Obligations and Commitments

We have $202.3 million of long-term tax reserves for uncertain tax positions, including interest and penalties, which are included in “Other liabilities” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See “Note 12 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2023, no long-term debt is due in the next twelve months and $600.0 million will be due subsequent to 2024. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We may seek to refinance all or a portion of our long-term debt obligations, including the 2023 Revolving Credit Facility, though any such refinancing transactions are subject to market and other conditions and there are no assurances that we will complete any such transactions, in whole or in part, or as to the amount or timing of any such transactions.

At December 31, 2023, $12.6 million of pension obligations will be due in the next twelve months and the remainder of $125.0 million will be due subsequent to 2024. See “Note 13 — Employee Benefit Plans” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. In addition, $9.9 million is due on a long-term basis under the Danish Holiday Act of 2020.

For a description of our operating lease obligations, refer to “Note 11 — Leases” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2023, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax, and other obligations in various jurisdictions. We expect to comply with the underlying performance requirements and we expect obligations under these letters of credit and surety bonds will not be called. At December 31, 2023, $16.9 million letters of credit and commercial commitments will expire in the next twelve months and the remainder of $98.6 million will expire subsequent to 2024.

We expect to fund these obligations and commitments with cash generated by our operations and cash on hand.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from our estimates and assumptions and any such differences could be material to our consolidated financial statements. The following accounting policies involve critical accounting estimates because they are particularly dependent on estimates and assumptions made by Noble about matters that are inherently uncertain.

Recoverability of Assets

We evaluate our property and equipment and intangible assets for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. To the extent actual results do not meet our estimated assumptions for a given rig, piece of equipment or intangible customer contract, we may take an impairment loss in the future. In determining the fair value of the assets, we make significant assumptions and estimates regarding future market conditions. Typical assumptions used in our estimate include current market conditions, timing of future contract awards, and expected operating dayrates, operating costs, utilization rates, discount rates, capital expenditures, market values, weighting of market values, reactivation costs, estimated economic useful lives, and marketability of a unit.

During the years ended December 31, 2023 and 2022, no impairment charges were recognized.

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Impairment assessment inherently involves management judgments as to assumptions about expected future cash flows and the impact of market conditions on those assumptions. Due to the many variables inherent in this estimation, differences in assumptions may have a material effect on the results of our impairment analysis.

Income Taxes

We estimate income taxes and file tax returns in each of the taxing jurisdictions in which we operate and are required to file a tax return. At the end of each year, an estimate for income taxes is recorded in the financial statements. Tax returns are generally filed in the subsequent year. A reconciliation of the estimate to the final tax return is done at that time, which will result in changes to the original estimate. We believe that our tax return positions are appropriately supported, but tax authorities can challenge certain of our tax positions.

We currently operate, and have in the past operated, in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50% likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. A change in judgment related to the expected ultimate resolution of uncertain tax positions will be recognized in earnings in the quarter of such change. We believe that our reserve for uncertain tax positions, including related interest and penalties, is adequate. As of December 31, 2023 and 2022, the Company had $202.3 million and $175.9 million of long-term tax reserves for unrecognized tax benefits, including interest and penalties, which are included in “Other liabilities.” The amounts ultimately paid upon resolution of audits could be materially different from the amounts previously included in our income tax expense and, therefore, could have a material impact on our tax provision, net income and cash flows.

Our gross deferred tax asset balance at year end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments, and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. In evaluating our ability to recover our deferred tax assets, in full or in part, we consider all available positive and negative evidence, including our past operating results and our forecast of future earnings, future taxable income, and prudent and feasible tax planning strategies. The assumptions utilized in determining future taxable income require significant judgment. Although we believe our assumptions, judgments, and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could have a material impact our consolidated financial statements.

Claims Reserves

We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability, and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.

Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. The amount of our loss reserves for personal injury and protection claims is based on an analysis performed by a third-party actuary which uses our historical loss patterns and trends as well as industry data to estimate the unpaid loss and allocated loss adjustment expense. Claim severity experienced in each year, ranging from minor incidents to permanent disability or injuries requiring extensive medical care, is a key driver of the variability around our reserve estimates. These estimates are further subject to uncertainty because the ultimate disposition of claims incurred is subject to the outcome of events which have not yet transpired. Accordingly, we may be required to increase or decrease our reserve levels. At December 31, 2023, loss reserves for personal injury and protection claims totaled $63.9 million, of which $21.9 million was included in “Other current liabilities” and $42.0 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets. At December 31, 2022, loss reserves for personal injury and protection claims totaled $35.3 million of which $15.5 million was included in “Other current liabilities” and $19.8 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets.

Business Combinations

We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair value. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeded the purchase price, we recognize a bargain purchase gain. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of

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operations in periods after acquisition. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed.

Our estimates of fair value of the acquired property and equipment and contract intangibles require us to use significant unobservable inputs, representative of a Level 3 fair value measurement, such as assumptions related to future marketability of each unit in light of the current market conditions and its current technical specifications, timing of future contract awards, and expected operating dayrates, operating costs, rig utilization rates, tax rates, discount rate, capital expenditures, synergies, market values, estimated economic useful lives of the rigs and, in certain cases, management’s belief that a drilling unit is no longer marketable and is unlikely to return to service in the near to medium term. It can be difficult to determine the fair value based on the cyclical nature of our business, demand for offshore drilling rigs in different markets, and changes in economic conditions.