UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2021

OR

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

For the transition period from _____ to _____

Commission file number 001-38373

TRANSOCEAN LTD.

(Exact name of registrant as specified in its charter)

Switzerland	98-0599916
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Turmstrasse 30
Steinhausen, Switzerland	6312
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: +41 (41) 749-0500

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbol	Name of each exchange on which registered
Shares, CHF 0.10 per share	RIG	New York Stock Exchange
0.50% Exchangeable Senior Bonds due 2023	RIG/23	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ☑   No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.   Yes ☐   No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ☑   No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes ☑   No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐
Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).   Yes ☐   No ☑ 

As of June 30, 2021, 634,629,502 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $2.87 billion (based on the reported closing market price of the shares of Transocean Ltd. on June 30, 2021 of $4.52 per share and assuming that all directors and executive officers of the Company are “affiliates,” although the Company does not acknowledge that any such person is actually an “affiliate” within the meaning of the federal securities laws).  As of February 14, 2022, 656,377,507 shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement to be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2021, for its 2022 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

TRANSOCEAN LTD. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2021

Item		Page
PART I
Item 1.	Business	2
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Reserved	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 8.	Financial Statements and Supplementary Data	41
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
Item 9A.	Controls and Procedures	74
Item 9B.	Other Information	74
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	74
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	75
Item 11.	Executive Compensation	75
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	75
Item 13.	Certain Relationships and Related Transactions, and Director Independence	75
Item 14.	Principal Accountant Fees and Services	75
PART IV
Item 15.	Exhibits and Financial Statement Schedules	76

Forward-Looking Information

The statements included in this annual report regarding future financial performance and results of operations and other statements that are not historical facts are forward-looking statements within the meaning of Section 27A of the United States (“U.S.”) Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of 1934.  Forward-looking statements in this annual report include, but are not limited to, statements about the following subjects:

◾ the effect, impact, potential duration, the scale of any economic disruptions or other implications of the COVID-19 pandemic, including virus variants;

◾ the effect of any disputes and actions with respect to production levels by, among or between major oil and gas producing countries and any expectations we may have with respect thereto;

◾ our results of operations, our cash flow from operations, our revenue efficiency and other performance indicators and optimization of rig-based spending;

◾ the offshore drilling market, including the effects of variations in commodity prices, supply and demand, utilization rates, dayrates, customer drilling programs, stacking and reactivation of rigs, effects of new rigs on the market, the impact of changes to regulations in jurisdictions in which we operate and changes in the global economy or market outlook for our industry, our rig classes or the various geographies in which we operate;

◾ customer drilling contracts, including contract backlog, force majeure provisions, contract awards, commencements, extensions, terminations, renegotiations, contract option exercises, contract revenues, early termination payments, indemnity provisions and rig mobilizations;

◾ the transition to renewable or other energy alternatives, the commitment, by us or our customers, to reduce greenhouse gas emissions or intensity thereof;

◾ liquidity, including availability under our bank credit agreement, and adequacy of cash flows for our obligations;

◾ debt levels, including interest rates, credit ratings and our evaluation or decisions with respect to any potential liability management transactions or strategic alternatives intended to prudently manage our liquidity, debt maturities and other aspects of our capital structure and any litigation, alleged defaults and discussions with creditors related thereto;

◾ newbuild, upgrade, shipyard and other capital projects, including the level of expected capital expenditures and the timing and cost of completing capital projects, delivery and operating commencement dates, relinquishment or abandonment, expected downtime and lost revenues;

◾ the cost and timing of acquisitions and the proceeds and timing of dispositions;

◾ tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues in the tax jurisdictions in which we operate or have a taxable presence;

◾ legal and regulatory matters, including results and effects of current or potential legal proceedings and governmental audits and assessments, outcomes and effects of internal and governmental investigations, customs and environmental matters;

◾ insurance matters, including adequacy of insurance, renewal of insurance, insurance proceeds and cash investments of our wholly owned captive insurance company;

◾ effects of accounting changes and adoption of accounting policies; and

◾ investment in recruitment, retention and personnel development initiatives, the timing of, and other matters concerning, severance payments and benefit payments.

Forward-looking statements in this annual report are identifiable by use of the following words and other similar expressions:

◾

anticipates

◾

budgets

◾

estimates

◾

forecasts

◾

may

◾

plans

◾

projects

◾

should

◾

believes

◾

could

◾

expects

◾

intends

◾

might

◾

predicts

◾

scheduled

Such statements are subject to numerous risks, uncertainties and assumptions, including, but not limited to:

◾ those described under “Item 1A. Risk Factors” in this annual report on Form 10-K;

◾ the effects of public health threats, pandemics and epidemics, such as the outbreak of COVID-19, and the adverse impact thereof on our business, financial condition and results of operations, including, but not limited to, our growth, operating costs, supply chain, labor availability, logistical capabilities, customer demand for our services and industry demand generally, our liquidity, the price of our securities and trading markets with respect thereto, our ability to access capital markets, and the global economy and financial markets generally;

◾ the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries and other oil and natural gas producing countries with respect to production levels or other matters related to the prices of oil and natural gas;

◾ the adequacy of and access to our sources of liquidity;

◾ our inability to renew drilling contracts at comparable, or improved, dayrates and to obtain drilling contracts for our rigs that do not have contracts;

◾ operational performance;

◾ the cancellation of drilling contracts currently included in our reported contract backlog;

◾ losses on impairment of long-lived assets;

◾ shipyard, construction and other delays;

◾ the results of meetings of our shareholders;

◾ changes in political, social and economic conditions;

◾ the effect and results of litigation, regulatory matters, settlements, audits, assessments and contingencies; and

◾ other factors discussed in this annual report and in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at www.sec.gov.

The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements.  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.  All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties.  You should not place undue reliance on forward-looking statements.  Each forward-looking statement speaks only as of the date of the particular statement.  We expressly disclaim any obligations 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, except as required by law.

PART I

Item 1.Business

Overview

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells.  As of February 14, 2022, we owned or had partial ownership interests in and operated a fleet of 37 mobile offshore drilling units, consisting of 27 ultra-deepwater floaters and 10 harsh environment floaters.  As of February 14, 2022, we were constructing two ultra-deepwater drillships.

We provide, as our primary business, contract drilling services in a single operating segment, which involves contracting our mobile offshore drilling rigs, related equipment and work crews to drill oil and gas wells.  We specialize in technically demanding regions of the global offshore drilling business with a particular focus on ultra-deepwater and harsh environment drilling services.  Our drilling fleet is one of the most versatile fleets in the world, consisting of drillships and semisubmersible floaters used in support of offshore drilling activities and offshore support services on a worldwide basis.

Transocean Ltd. is a Swiss corporation with its registered office in Steinhausen, Canton of Zug and with principal executive offices located at Turmstrasse 30, 6312 Steinhausen, Switzerland.  Our telephone number at that address is +41 41 749-0500.  Our shares are listed on the New York Stock Exchange under the ticker symbol “RIG.”  For information about the revenues, operating income, assets and other information related to our business, our segments and the geographic areas in which we operate, see “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 1—Business, Note 5—Revenues and Note 7—Long-Lived Assets.”

Drilling Fleet

Overview—We provide contract drilling services using our fleet of mobile offshore drilling units, including both drillships and semisubmersibles, broadly referred to as floaters.  Floaters are designed to operate in locations away from port for extended periods of time and have living quarters for the crews, a helicopter landing deck and storage space for drill pipe, riser and drilling supplies.  Our drilling units and related equipment are suitable for both exploration and development, and we engage in both types of activities.

Drillships are floating vessels that are shaped like conventional ships, generally self-propelled and considered to be the most mobile of the major rig types.  Drillships typically have greater deck load and storage capacity than semisubmersible rigs, which provides logistical and resupply efficiency benefits for customers.  Drillships are generally better suited to operations in calmer sea conditions and typically do not operate in areas considered to be harsh environments.  Our high-specification drillships are equipped with dynamic positioning thruster systems, which allows them to maintain position without anchors through the use of onboard propulsion and station-keeping systems.  We have 22 ultra-deepwater drillships that are, and two ultra-deepwater drillships under construction that will be, equipped with our patented dual-activity technology.  Dual-activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to allow these drillships to perform simultaneous drilling tasks in a parallel, rather than a sequential manner, which reduces critical path activity and improves efficiency in both exploration and development drilling.  In addition to dynamic positioning thruster systems, dual-activity technology and industry-leading hoisting capacity, our contracted newbuild drillships under construction will be equipped with at least one 20,000 pounds per square inch (“psi”) blowout preventers.

Semisubmersibles are floating vessels that can be partially submerged by means of a water ballast system such that the lower column sections and pontoons are below the water surface during drilling operations.  Semisubmersibles are known for stability, making them well suited for operating in rough sea conditions.  Semisubmersible floaters are capable of maintaining their position over a well either through dynamic positioning or the use of mooring systems.  Although most semisubmersible rigs are relocated with the assistance of tugs, some units are self-propelled and move between locations under their own power when afloat on pontoons.  Four of our 13 semisubmersibles are equipped with dual-activity technology and also have mooring capability.  Two of these four dual-activity units are custom-designed, high-capacity semisubmersible drilling rigs, equipped for year-round operations in harsh environments, including those of the Norwegian continental shelf and sub-Arctic waters.

Our floater fleet consists of ultra-deepwater floaters and harsh environment floaters that are designed with high-specification capabilities to operate in the technically demanding regions of the global offshore drilling business.  Ultra-deepwater floaters are equipped with high-pressure mud pumps and are capable of drilling in water depths of 4,500 feet or greater.  Harsh environment floaters are capable of drilling in harsh environments in water depths between 1,500 and 10,000 feet and have greater displacement, which offers larger variable load capacity, more useable deck space and better motion characteristics.

Fleet status—Depending on market conditions, we may idle or stack our non-contracted rigs.  An idle rig is between drilling contracts, readily available for operations, and operating costs are typically at or near normal operating levels.  A stacked rig typically has reduced operating costs, is staffed by a reduced crew or has no crew and is (a) preparing for an extended period of inactivity, (b) expected to continue to be inactive for an extended period, or (c) completing a period of extended inactivity.  Stacked rigs will continue to incur operating costs at or above normal operating levels for approximately 30 days following initiation of stacking.  Some idle rigs and all stacked rigs require additional costs to return to service.  The actual cost to return to service, which in many instances could be significant and could fluctuate

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over time, depends upon various factors, including the availability and cost of shipyard facilities, the cost of equipment and materials, the extent of repairs and maintenance that may ultimately be required, the length of time a rig has spent in stacking mode and time and cost of assembling and training crew.  We consider these factors, together with market conditions, length of contract, dayrate and other contract terms, when deciding whether to return a stacked rig to service.  We may not return some stacked rigs to work for drilling services.

Drilling units—The following tables, presented as of February 14, 2022, provide certain specifications for our rigs.  Unless otherwise noted, the stated location of each rig indicates either the current drilling location, if the rig is operating, or the next operating location, if the rig is in shipyard with a follow-on contract.  The dates provided represent the expected time of completion, the year placed into service, and, if applicable, the year of the most recent upgrade.  As of February 14, 2022, we owned all of the drilling rigs in our fleet noted in the tables below, except for the following: (1) the harsh environment floater Transocean Norge, which is owned through our 33.0 percent ownership interest in Orion Holdings (Cayman) Limited (together with its subsidiary, “Orion”), and (2) the ultra-deepwater floater Petrobras 10000, which is subject to a finance lease through August 2029.

			Year	Water	Drilling	Contracted
			entered	depth	depth	location or
			service /	capacity	capacity	standby
Rig category and name	Specifications	Type	upgraded	(in feet)	(in feet)	status
Ultra-deepwater floaters (27)
Deepwater Poseidon	(a) (b) (c) (d)	Drillship	2018	12,000	40,000	U.S. Gulf
Deepwater Pontus	(a) (b) (c) (d)	Drillship	2017	12,000	40,000	U.S. Gulf
Deepwater Conqueror	(a) (b) (c) (d)	Drillship	2016	12,000	40,000	U.S. Gulf
Deepwater Proteus	(a) (b) (c) (d)	Drillship	2016	12,000	40,000	U.S. Gulf
Deepwater Thalassa	(a) (b) (c) (d)	Drillship	2016	12,000	40,000	U.S. Gulf
Ocean Rig Apollo	(a) (b)	Drillship	2015	12,000	40,000	Stacked
Deepwater Athena	(a) (b)	Drillship	2014	12,000	40,000	Stacked
Deepwater Asgard	(a) (b) (c)	Drillship	2014	12,000	40,000	U.S. Gulf
Deepwater Invictus	(a) (b) (c)	Drillship	2014	12,000	40,000	U.S. Gulf
Deepwater Skyros	(a) (b)	Drillship	2013	12,000	40,000	Angola
Deepwater Mylos	(a) (b) (c)	Drillship	2013	12,000	40,000	Stacked
Deepwater Champion	(a) (b)	Drillship	2011	12,000	40,000	Stacked
Deepwater Corcovado	(a) (b)	Drillship	2011	10,000	35,000	Brazil
Deepwater Mykonos	(a) (b)	Drillship	2011	10,000	35,000	Brazil
Deepwater Orion	(a) (b)	Drillship	2011	10,000	35,000	Idle
Deepwater Olympia	(a) (b)	Drillship	2011	10,000	35,000	Stacked
Discoverer India	(a) (b)	Drillship	2010	12,000	40,000	Stacked
Discoverer Luanda	(a) (b)	Drillship	2010	7,500	40,000	Stacked
Dhirubhai Deepwater KG2	(a)	Drillship	2010	12,000	35,000	Idle
Discoverer Inspiration	(a) (b) (c)	Drillship	2010	12,000	40,000	U.S. Gulf
Discoverer Americas	(a) (b)	Drillship	2009	12,000	40,000	Stacked
Development Driller III	(a) (b) (e)	Semisubmersible	2009	7,500	37,500	Idle
Petrobras 10000	(a) (b)	Drillship	2009	12,000	37,500	Brazil
Discoverer Clear Leader	(a) (b) (c)	Drillship	2009	12,000	40,000	Stacked
Dhirubhai Deepwater KG1	(a)	Drillship	2009	12,000	35,000	India
GSF Development Driller I	(a) (b) (e)	Semisubmersible	2005	7,500	37,500	Stacked
Deepwater Nautilus	(e)	Semisubmersible	2000	8,000	30,000	Not Disclosed
Harsh environment floaters (10)
Transocean Norge	(a) (e) (f)	Semisubmersible	2019	10,000	40,000	Norwegian N. Sea
Transocean Enabler	(a) (e) (f)	Semisubmersible	2016	1,640	28,000	Norwegian N. Sea
Transocean Encourage	(a) (e) (f)	Semisubmersible	2016	1,640	28,000	Norwegian N. Sea
Transocean Endurance	(a) (e) (f)	Semisubmersible	2015	1,640	28,000	Norwegian N. Sea
Transocean Equinox	(a) (e) (f)	Semisubmersible	2015	1,640	28,000	Norwegian N. Sea
Transocean Spitsbergen	(a) (e) (f) (g)	Semisubmersible	2010	10,000	30,000	Norwegian N. Sea
Transocean Barents	(a) (e) (g)	Semisubmersible	2009	10,000	30,000	Norwegian N. Sea
Henry Goodrich	(e)	Semisubmersible	1985/2007	5,000	30,000	Stacked
Transocean Leader	(e)	Semisubmersible	1987/1997	4,500	25,000	Stacked
Paul B. Loyd, Jr.	(e)	Semisubmersible	1990	2,000	25,000	U.K. N. Sea

(a) Dynamically positioned.

(b) Patented dual activity.

(c) Two blowout preventers.

(d) Designed to accommodate a future upgrade to 20,000 psi blowout preventers.

(e) Moored.

(f) Automated drilling control.

(g) Dual activity.

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				Water	Drilling
				depth	depth
			Expected	capacity	capacity	Contracted
Rig category and name	Specifications	Type	completion	(in feet)	(in feet)	location
Rigs under construction (2)
Ultra-deepwater floaters
Deepwater Atlas	(a) (b) (c)	Drillship	2H2022	12,000	40,000	U.S. Gulf
Deepwater Titan	(a) (b) (d)	Drillship	1H2023	12,000	40,000	U.S. Gulf

(a) To be dynamically positioned.

(b) To be equipped with our patented dual activity.

(c) To be equipped with one 20,000 psi blowout preventer and one 15,000 psi blowout preventer.

(d) To be equipped with two 20,000 psi blowout preventers.

Drilling Contracts

Our offshore drilling services contracts are individually negotiated and vary in their terms and conditions.  We obtain most of our drilling contracts through bidding processes in competition against other drilling services contractors and through direct negotiations with operators.  Drilling contracts generally provide for payment on a dayrate basis, typically with higher rates for periods when drilling operations are optimized and lower or zero rates for periods during which the drilling unit is mobilized or when drilling operations are interrupted, restricted by equipment breakdowns, adverse environmental conditions or otherwise.  A dayrate drilling contract generally extends over a period of time either covering the drilling of a single well or group of wells or covering a stated term.  At December 31, 2021, our contract backlog was approximately $6.60 billion, representing a decrease of 18 percent and 37 percent, respectively, compared to the contract backlog at December 31, 2020 and 2019, which was $8.06 billion and $10.42 billion, respectively.  See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators.”

Certain of our drilling contracts may be cancelable for the convenience of the customer, typically with the payment of an early termination payment.  Such payments, however, may not fully compensate us for the loss of the contract.  Drilling contracts also customarily provide for either automatic termination or termination at the option of the customer, typically without payment of any termination fee, under various circumstances such as non-performance, in the event of extended downtime or impaired performance due to equipment or operational issues or periods of extended downtime due to force majeure events.  Many of these events are beyond our control.  The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional period of time.  Our contracts also typically include a provision that allows the customer to extend the contract to finish drilling a well-in-progress.  During periods of depressed market conditions, our customers may seek to renegotiate drilling contracts or options to reduce the term of their obligations or the average dayrate through term extensions or may seek to early terminate or repudiate their contracts.  Suspension of drilling contracts will result in the reduction in or loss of dayrate for the period of the suspension.  If customers cancel some of our contracts and we are unable to secure new contracts on a timely basis and on substantially similar or more favorable terms, if some of our contracts are suspended for an extended period of time or if a number of our contracts are renegotiated on less favorable terms, our consolidated financial position, results of operations or cash flows may be adversely affected.  See “Item 1A. Risk Factors—Risks related to our business—Our drilling contracts may be terminated due to a number of events, and, during depressed market conditions, our customers may seek to repudiate or renegotiate their contracts.”

Under dayrate drilling contracts, consistent with standard industry practice, our customers, as the operators, generally assume, and grant indemnity for, subsurface and well control risks, and their consequential damages.  Under all of our current drilling contracts, our customers indemnify us for pollution damages in connection with reservoir fluids stemming from operations under the contract, and we indemnify our customers for pollution that originates above the surface of the water from the rig from substances in our control, such as diesel used onboard the rig or other fluids stored onboard the rig.  Also, our customers indemnify us for consequential damages they incur, damage to the well or reservoir, loss of subsurface oil and gas and the cost of bringing the well under control.  However, because our drilling contracts are individually negotiated, the degree of indemnification we receive from our customers for the risks discussed above may vary from contract to contract based on market conditions, customer requirements existing when the contract was negotiated or other factors.  In some instances, we have contractually agreed upon certain limits to our indemnification rights and can be responsible for certain damages up to a specified maximum dollar amount.  The nature of our liability and the prevailing market conditions, among other factors, can influence such contractual terms.  Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations.

The interpretation and enforceability of a contractual indemnity depends upon the specific facts and circumstances involved, as governed by applicable laws, and may ultimately need to be decided by a court or other proceeding, which would need to consider the specific contract language, the facts and applicable laws.  Applicable laws often consider contractual indemnity for criminal fines and penalties to be against public policy.  Many courts also restrict indemnification for criminal fines and penalties.  The inability or other failure of our customers to fulfill their indemnification obligations, or the unenforceability of all of our contractual protections could have a material adverse effect on our consolidated financial position, results of operations or cash flows.  See “Item 1A. Risk Factors—Risks related to our business—Our business involves numerous operating hazards, and our insurance and indemnities from our customers may not be adequate to cover potential losses from our operations.”

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Markets

Overview—Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world.  We operate in a single, global offshore drilling market, as our drilling rigs are mobile assets and can be moved according to prevailing market conditions.  We may mobilize our drilling rigs between regions for a variety of reasons, including to respond to customer contracting requirements or to capture observed market demand.  Consequently, we cannot predict the future percentage of our revenues that will be derived from particular geographic areas.  As of February 14, 2022, the drilling units in our fleet, including stacked and idle rigs, but excluding rigs under construction, were located in Greece (eight units), the U.S. Gulf of Mexico (eight units), the Norwegian North Sea (seven units), Brazil (three units), Malaysia (three units), the United Kingdom (the “U.K.”) North Sea (two units), Trinidad (one unit), Angola (one unit), Canada (one unit), India (one unit), Myanmar (one unit), and Namibia (one unit).

We categorize the sectors of the floater market in which we operate as follows: (1) ultra-deepwater and deepwater, (2) harsh environment and (3) midwater.  We typically employ our ultra-deepwater floaters to service the ultra-deepwater and deepwater sector, and we employ our harsh environment floaters to service all three sectors.  We generally view the ultra-deepwater and deepwater market sector as water depths beginning at 4,500 feet and extending to the maximum water depths in which rigs are capable of drilling, which is currently up to 12,000 feet.  The midwater market sector includes water depths from approximately 300 feet to approximately 4,500 feet.  The harsh environment market sector includes regions that are more challenged by lower temperatures, harsher weather conditions and water currents.

The market for offshore drilling rigs and related services reflects our customers’ demand for equipment for drilling exploration, appraisal and development wells and for performing maintenance on existing production wells.  Activity levels of energy companies, including integrated energy companies, independent energy companies and, to a lesser extent, national energy companies are largely driven by the worldwide demand for energy, including crude oil and natural gas.  Worldwide energy supply and demand drives oil and natural gas prices, which, in turn, impact energy companies’ ability to fund investments in exploration, development and production activities.

Outlook—In 2014, the industry began to experience a severe cyclical downturn that has proven to be of considerably longer duration than those previously observed.  Multiple years of volatile and generally weak commodity prices, exacerbated by the effects of the COVID-19 pandemic and production disputes among major oil producing countries, resulted in our customers delaying offshore investment decisions and postponing exploration and development programs.  Some of our customers have also committed to invest or increase investment in low carbon and renewable energy resources, potentially affecting their expenditures in the development and production of hydrocarbons over the coming decades.  Even in the context of some diversion of investment away from traditional energy sources, the structural efficiency gains achieved by the offshore oil and gas industry during the past seven years materially improved the economics of deepwater and harsh environment offshore development projects.  Our services are central to the exploitation of these competitive sources of new supply.

Our overall outlook for the offshore drilling industry has improved over the past year and remains positive, particularly for high-specification assets, such as those we own and operate.  During the second half of 2021, our customers’ interest in deepwater and harsh environment offshore projects was renewed due to numerous favorable factors, such as sustained higher commodity prices and comparably lower carbon intensity compared to other sources of fossil fuel.  South America, including Guyana, the U.S. Gulf of Mexico and, increasingly, West Africa remain key ultra-deepwater market sectors, while Norway continues to represent the largest harsh environment market.

In addition, in 2021, we observed continued strong tendering activity for Asia and Australia.  Licensing activity also indicated an increased interest in these areas as energy companies looked to explore and develop new prospects.  Certain customers began to increase their exploration, production and reserve replacement activities by restarting delayed projects and commencing new campaigns.  We have seen an acceleration in this trend in early 2022.  While we expect this to continue in the near term, and potentially longer, it depends upon many variables, including increased global demand for hydrocarbons, the effects of the COVID-19 pandemic on consumer activity, the actions by some governments and regulators intended to curtail existing and future drilling activities, and other factors.

We expect offshore oil and gas production to be a significant part of the long-term strategy for energy companies as they strive to meet the global demand for energy sources and hydrocarbons.  These projects are technically demanding due to various factors, such as water depth, complex well designs, deeper drilling depth, high pressure and temperature, sub-salt geological formations, harsh environments, and heightened regulatory standards necessitating the use of high-specification drilling units.  Generally, high-specification rigs are the most modern, technologically advanced class of the offshore fleet and have capabilities that are attractive to energy companies operating in deeper water depths, other challenging environments or with complex well designs.  We have led the industry and made concerted efforts since the beginning of the prolonged downturn to high-grade our fleet profile by acquiring high-specification assets and disposing of lower-specification assets.  In this regard, during the years ended December 31, 2021, 2020 and 2019, we sold for scrap value one, six and eleven lower-specification drilling units, respectively.

As the hydrocarbon supply-demand balance further improves, we expect sustained prices to increase demand for our high-specification fleet of assets and, because there are now fewer offshore drilling rigs than in recent years, further improvement of dayrates.  See “Item 1A. Risk Factors—Risks related to our business.”

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Customers

We provide our offshore drilling services to most of the leading integrated energy companies or their affiliates, as well as for many government-owned or government-controlled energy companies and other independent energy companies.  For the year ended December 31, 2021, our most significant customers were Shell plc (together with its affiliates, “Shell”) and Equinor ASA (together with its affiliates, “Equinor”), representing approximately 31 percent and 30 percent, respectively, of our consolidated operating revenues.  No other customers accounted for 10 percent or more of our consolidated operating revenues in the year ended December 31, 2021.  Additionally, as of February 14, 2022, the customers with the most significant aggregate amount of contract backlog associated with our drilling contracts were Shell, Equinor and Chevron Corporation (together with its affiliates, “Chevron”), representing approximately 54 percent, 16 percent and 15 percent, respectively, of our total contract backlog.  See “Item 1A. Risk Factors—Risks related to our business—We rely heavily on a relatively small number of customers and the loss of a significant customer or a dispute that leads to the loss of a customer could have an adverse effect on our business.”

Human Capital Resources

Worldwide workforce—As of December 31, 2021, we had a global workforce of approximately 5,530 individuals, including approximately 530 contractors, representing 58 nationalities.  At December 31, 2021, our global workforce is geographically distributed in 21 countries across five continents as follows: 34 percent in North America, 32 percent in Europe, 17 percent in South America, 12 percent in Asia and 5 percent in Africa.

FIRST Shared Values and corporate culture—Our FIRST Shared Values serve as the foundation for our corporate culture and guide us to act ethically and responsibly as we strive to deliver value for our stakeholders and to maintain a safe and respectful work environment for our people.  Our Shared Values are as follows:

◾ Focused.  We will consistently exceed the expectations of customers, shareholders and employees.

◾ Innovative.  We will continuously advance our position as technical leaders, and relentlessly pursue improvement in all that we do.

◾ Reliable.  We will execute flawlessly by ensuring that our equipment, processes and systems always perform as and when intended, and that our people are properly trained and motivated.

◾ Safe.  Above all else, we will protect each other, the environment and our assets.  We will conduct our operations in an incident-free environment, all the time, everywhere.

◾ Trusted.  We will always act with integrity and professionalism, honor our commitments, comply with laws and regulations, respect local cultures, and be fiscally responsible.

Code of Integrity and Human Rights—We maintain a Code of Integrity and Human Rights Policy that applies to all our board members, executives, employees and business partners, including contractors, suppliers, vendors, investees and joint venture partners.  We demonstrate our respect of human rights by maintaining a healthy and safe work environment, observing fair employment practices and providing competitive employment terms.  Practices such as modern slavery, child labor, forced or indentured servitude, and other human rights abuses are strictly prohibited.

Labor rights—We respect the labor rights of all individuals in our workforce, including the right to collective bargaining.  Approximately 42 percent of our total workforce, working primarily in Norway, Brazil and the U.K., are represented by, and some of our contracted labor work is subject to, collective bargaining agreements, substantially all of which are subject to annual salary negotiation.  Negotiations over annual salary or other labor matters could result in higher personnel or other costs or increased operational restrictions or disruptions.  The outcome of any such negotiation generally affects the market for all offshore employees, not only union members.  A failure to reach an agreement on certain key issues could result in strikes, lockouts or other work stoppages.

Attraction, development and retention—We aim to strategically cultivate a best-in-class workforce to offer the innovation, local knowledge and experience required of the world’s premier offshore drilling contractor.  We seek to maintain our competitive advantage while benefitting our local communities by offering regionally competitive compensation and benefits packages, a technically challenging work environment, global opportunities, and rotational development programs.  We continually assess and adapt our offerings and our policies, based on evolving social and technological practices, to provide a modern work environment, which is essential to attract and retain top talent, and a respectful and inclusive work environment in which our global workforce can thrive.  Our focus on the quality of our workforce is designed to maximize the quality of our work performance and ultimately, the value we deliver to our stakeholders.

Training—We invest in our workers by providing them with the transferrable skill sets essential to advancing their professional development.  To ensure our business competes at the highest levels, we maintain a rigorous competency-based training program.  Our internal training board maintains and regularly updates our training matrix to meet or exceed industry standards, and it oversees our competency assurance management system, which is accredited by the Offshore Petroleum Industry Training Organization.  We provide various offshore training formats designed to encompass all learning styles through on-the-job, e-learning, customer-specific training, certifications, and leadership and licensing programs.  Setting us apart from our competitors, we also offer unique simulation-based education, augmented by digital twin modeling, enabling our workforce to more accurately visualize equipment performance and target efficiencies.  The certifications, skills and competencies needed for each role are clearly articulated to our workforce, and workers are required to successfully complete the relevant training and attain all necessary certifications prior to taking on new roles.

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Wellness and benefits—We offer our workforce regionally competitive medical and financial benefits, tailored to our workforce demographics.  We design our wellness and benefits strategy under four pillars consisting of physical well-being, financial well-being, emotional well-being and social well-being, emphasizing during the pandemic, as a key benefit, our globally available employee assistance program.

Safety—Our safety vision is to conduct our operations in an incident-free workplace, all the time, everywhere.  As a socially responsible company, we prioritize the protection of everyone aboard our rigs and in our facilities, the environment and our property at all work locations and during all operations.  We require compliance with all local regulations and a comprehensive set of internal policies and procedures that govern our operations, including health and safety protocols for COVID-19 mitigation.  With regular competency and effectiveness assessments, our highly trained crews are equipped to protect our operational integrity with the process-driven management of hazards to prevent and mitigate major hazard accidents.  We measure our safety performance in terms of widely accepted ratios with the use of industry standards, including (a) the total recorded incidence rate (“TRIR”), which represents the number of recordable work-related injuries or illnesses for every 200,000 hours worked, and (b) the lost time incidence rate (“LTIR”), which measures the number of incidents that result in lost time due to work-related injuries or illnesses for every 200,000 hours worked.  In the year ended December 31, 2021, our TRIR was 0.26, and our LTIR was 0.02.

Environmental Responsibility

We understand our business has an impact on the environment.  Our objective is to deliver our services in a manner that minimizes the impact to the environment and supports the interests of our stakeholders.  We constantly seek new ways to advance our commitment to safely performing our operations while simultaneously safeguarding the environment in which we operate.  We maintain a global Environmental Management System (“EMS”) standard that is applied to our rigs, offices and facilities.  The EMS is aligned to ISO 14001 and provides a framework to ensure that our worldwide operations are managed consistently and continuously in an environmentally responsible manner.

We regularly assess the environmental impacts of our operations, focusing on the reduction of greenhouse gas emissions, operational discharges and water use, through increasing energy efficiency and waste minimization.  Our actions are designed to reduce risk in our current and future operations, to promote sound environmental management practices and to continue to be proactive in managing and reducing our environmental footprint.  Our investments and deployment of capital and technology reflect our commitment to improve the energy and emission efficiency of our operations.

Another way we seek to enhance our operational performance is by setting emissions targets.  We intend to reduce our operating Scope 1 and Scope 2 greenhouse gas emissions intensity by 40 percent from 2019 levels by 2030.  Achieving these targets will require investments over time that result in the development and implementation of new technologies, reduced fuel consumption and other initiatives that enable us to optimize our power management capabilities.

When we have decommissioned older and less capable assets, we have demonstrated our commitment to recycle them according to established environmental regulations and guidelines.  All the rigs that we have sold for scrap value have been safely and responsibly recycled following protocols established under the Basel Convention and by the International Maritime Organization at the Hong Kong International Convention.

Technological Innovation

We have a long history of technological innovation, including the first dynamically positioned drillship, the first rig to drill year-round in the North Sea, the first semisubmersible rig for year-round sub-Arctic operations, the first 10,000-ft. water depth rated ultra-deepwater drillship and numerous water depth world records over the past several decades.  Twenty-two drillships and two semisubmersibles in our existing fleet are, and our two drillships that are under construction will be, equipped with our patented dual-activity technology, which allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner, reducing well construction critical path activities and, thereby, improving efficiency in both exploration and development drilling.

We continue to develop and deploy industry-leading technology in the pursuit of delivering safer, more efficient and environmentally responsible drilling services.  In addition to our patented dual-activity drilling technology, our two drillships under construction will include industry-leading 3.5 million-pound hoisting load capability, hybrid energy storage systems for enhanced drill floor equipment reliability, fuel and emissions savings as well as advanced generator protection for power plant reliability.  Ten drillships in our existing fleet are, and our two drillships that are under construction will be, outfitted with dual blowout preventers and triple liquid mud systems.  Our two drillships under construction will be equipped with 20,000 psi blowout preventers and related equipment.  Five drillships in our existing fleet are designed to accept 20,000 psi blowout preventers in the future.  We also continue to develop and invest in technologies designed to optimize our performance and deliver ever better operational integrity through innovations, such as our proprietary fault-resistant and fault-tolerant blowout preventer control system.

Seven of our harsh environment semisubmersibles are designed and constructed specifically to provide highly efficient performance in the Norwegian North Sea and in the Barents Sea.  We have installed automated drilling control systems on six harsh environment floaters, which materially improves our ability to safely and efficiently deliver wells to our customers.

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We employ a data-driven approach by deploying technology, augmented by the size of our fleet, to expand our knowledge framework for sustainable process optimization.  In 2020, we deployed our smart equipment analytics tool, which delivers real-time data feeds from equipment to monitor equipment health, inferred emissions and energy consumption while identifying performance trends that allow us to systematically optimize equipment maintenance and achieve higher levels of reliability, operational efficiency and sustainability.

Driven by our continued focus on safety, we developed and deployed our patented HaloGuard℠ system, which alarms, notifies and, if required, halts equipment to avoid injury to personnel who move into danger zones.  We recently deployed the first unit of Enhanced Drilling’s EC-Monitor system to an offshore installation, enabling highly accurate understanding of well fluid dynamics and improving the efficiency and accuracy of flow-checking and detecting flow anomalies.  Additionally, in 2021, we deployed on one of our ultra-deepwater drillships the first kinetic blowout stopper, a step-changing technology operations integrity and enterprise risk reduction through unrivaled shearing capability.  In the first half of 2022, we expect to be the first to deploy offshore a robotic riser bolting tool on two of our ultra-deepwater drillships, improving our ability to deliver safe, efficient and operations to our customers.

We believe our efforts to continuously improve, and effectively use, innovative technologies to meet or exceed our customers’ requirements is critical to maintaining our competitive position within the contract drilling services industry by drilling more efficient wells, building greater resilience into our critical operating systems, ensuring the safety of our crews, and reducing fuel consumption and emissions.

Governmental Regulations

Our operations are subject to a variety of international, regional, national, state and local government regulations, including environmental regulations.  We monitor our compliance with such government regulations in each country of operation and, while we see an increase in many government regulations, particularly general environmental regulation, we have made and will continue to make the required expenditures to comply with current and future government requirements.  To date, we have not incurred material costs in order to comply with such government regulations, including environmental regulations, and do not expect to make any material capital expenditures in order to comply with such regulations in the year ending December 31, 2022, or any other period contemplated at this time.  We do not believe that our compliance with such requirements will have a material adverse effect on our competitive position, consolidated results of operations or cash flows.  We incorporate by reference into this subsection “—Government Relations” the disclosures on government regulations, including environmental regulations, contained in the following sections of this annual report on Form 10-K:

◾ “Item 1A. Risk Factors—Risks related to our laws, regulations and governmental compliance;”

◾ “Item 3. Legal Proceedings;”

◾ “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other Matters;”

◾ “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 11—Income Taxes;” and

◾ “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 13—Commitments and Contingencies.”

Joint Venture, Agency and Sponsorship Relationships and Other Investments

In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation since local laws or customs in those areas effectively mandate the establishment of a relationship with a local agent or sponsor.  When appropriate in these areas, we may enter into agency or sponsorship agreements.  We also invest in certain companies for operational and strategic purposes.  Some of these joint ventures or companies in which we are an investor are involved in researching and developing technology to improve efficiency, reliability, sustainability and safety for our drilling and other activities or are involved in businesses developed to support the transition to renewable or other energy alternatives.  We may or may not control these partially owned companies.  At December 31, 2021, we held partial ownership interests in companies organized in the Cayman Islands, the U.S., Norway, Canada and other countries, the most significant of which was our 33.0 percent ownership interest in Orion, an unconsolidated Cayman Islands exempted company formed to construct and own the harsh environment semisubmersible Transocean Norge.  Certain affiliates of Hayfin Capital Management LLP, own the remaining 67.0 percent ownership interest in Orion not owned by us.

Available Information

Our website address is www.deepwater.com.  Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 10-K and should not be considered a part of this report or any other filing that we make with the SEC.  Furthermore, references to our website URLs are intended to be inactive textual references only.  We make available on this website free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.  You may also find on our website information related to our corporate governance, board committees and company code of business conduct and ethics.  The SEC also maintains a website, www.sec.gov, which contains reports, proxy statements and other information regarding SEC registrants, including us.  We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Integrity and any waiver from any provision of our Code of Integrity by posting such information in the Governance page on our website at www.deepwater.com.

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Item 1A.Risk Factors

Risks related to our business

Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by volatile oil and gas prices and other factors.

Our business depends on oil and gas exploration, development and production in offshore areas where we are capable of operating.  Demand for our services depends on these activities and related expenditure levels that are directly affected by trends in oil and, to a lesser extent, natural gas prices.  Oil and gas prices are extremely volatile and are affected by numerous factors, including the following:

◾ worldwide demand for oil and gas, including economic activity in the U.S., other large energy-consuming markets and in developing and emerging markets, which has been significantly impacted by the COVID-19 pandemic and the governmental, company and individual reactions thereto;

◾ the ability of the Organization of the Petroleum Exporting Countries (“OPEC”) to set and maintain production levels, productive spare capacity and pricing among its members;

◾ the level of production in non-OPEC countries;

◾ inventory levels, and the cost and availability of storage and transportation of oil, gas and their related products;

◾ the policies, laws and regulations of various governments regarding exploration and development of their oil and gas reserves and environmental matters, including those addressing alternative energy sources and the risks of global climate change;

◾ international sanctions on oil-producing countries, or the lifting of such sanctions;

◾ advances in exploration, development and production technology;

◾ the development, exploitation and market acceptance of alternative energy sources;

◾ the further development of shale technology to exploit oil and gas reserves;

◾ the discovery rate of new oil and gas reserves and the rate of decline of existing oil and gas reserves;

◾ accidents, adverse weather conditions, natural disasters and other similar incidents relating to the oil and gas industry; and

◾ the worldwide security and political environment, including uncertainty or instability resulting from an escalation or outbreak of armed hostilities, civil unrest, acts of terrorism, public health threats or other crises.

Demand for our services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, energy companies, including national energy companies.  Prolonged reductions in oil and natural gas prices could depress the immediate levels of exploration, development and production activity.  Perceptions of longer-term lower oil and natural gas prices by energy companies, or a perception that the demand for hydrocarbons will significantly decrease in the medium to long term, could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects and capital reinvestment policies.  Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability.  Oil and gas prices and market expectations of potential changes in these prices significantly affect this level of activity.  However, increases in near-term commodity prices do not necessarily translate into increased offshore drilling activity since customers’ expectations of longer-term future commodity prices and expectations regarding future demand for hydrocarbons typically have a greater impact on demand for our rigs.  Consistent with this dynamic, customers may delay or cancel many exploration and development programs, resulting in reduced demand for our services.  Also, increased competition for customers’ drilling budgets could come from, among other areas, land-based energy markets worldwide.  The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect customers’ drilling campaigns.  Worldwide military, political and economic events have often contributed to oil and gas price volatility and are likely to do so in the future.

The offshore drilling industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which has a dominant market share.  Drilling contracts are traditionally awarded on a competitive bid basis.  Although rig availability, service quality and technical capability are drivers of customer contract awards, bid pricing and intense price competition are often key determinants for which a qualified contractor is awarded a job.

The offshore drilling industry is highly cyclical and is impacted by oil and natural gas price levels and volatility.  Periods of high customer demand, limited rig supply and high dayrates have been followed by periods of low customer demand, excess rig supply and low dayrates.  Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply may intensify competition in the industry and result in the idling of older and less technologically advanced equipment.  We have idled and stacked rigs, and may in the future idle or stack additional rigs or enter into lower dayrate drilling contracts in response to market conditions.  Idled or stacked rigs may remain out of service for extended periods of time.  During prior periods of high dayrates and rig utilization rates, we and other industry participants responded to increased customer demand by increasing the supply of rigs through ordering the construction of new units.  The number of new units delivered without contracts, combined with an increased number of rigs in the global market completing contracts and becoming idle, has increased and may continue to intensify price competition.  During periods of low oil and natural gas price levels, new construction has resulted in an oversupply of rigs and has caused a subsequent decline in dayrates and rig utilization rates, sometimes for extended periods of time.  In an oversupplied market, we may have limited bargaining power to negotiate on more favorable terms.  Additionally, lower market dayrates and intense price competition may drive customers to seek to renegotiate existing contracts to reduce dayrates in exchange for longer contract terms.  Lower dayrates and rig utilization rates could adversely affect our revenues and profitability.

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As of February 14, 2022, we have 15 uncontracted rigs, of which five have been out of service for greater than five years, and these rigs may remain out of service for extended periods of time.  If we are unable to obtain drilling contracts for our uncontracted rigs, whether due to a prolonged offshore drilling market downturn, a delayed or muted recovery of such market or otherwise, it may have an adverse effect on our results of operations and cash flows.

We may not be able to renew or obtain new drilling contracts for rigs whose contracts are expiring or obtain drilling contracts for our stacked and idle rigs.

The offshore drilling markets in which we compete experience fluctuations in the demand for drilling services.  Our ability to renew expiring drilling contracts or obtain new drilling contracts depends on the prevailing or expected market conditions at the time of expiration.  As of February 14, 2022, we have 15 stacked or idle rigs.  We also have 11 existing drilling contracts for our rigs that are currently operating, which are scheduled to expire before December 31, 2022.  We may be unable to obtain drilling contracts for our rigs that are currently operating upon the expiration or termination of such contracts, and there may be a gap in the operation of the rigs between the current contracts and subsequent contracts.  When oil and natural gas prices are low or it is expected that such prices will decrease in the future, we may be unable to obtain drilling contracts at attractive dayrates or at all.  We may not be able to obtain new drilling contracts in direct continuation with existing contracts, or depending on prevailing market conditions, we may enter into drilling contracts at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms, which may have an adverse effect on our financial position, results of operations or cash flows.

Our current backlog of contract drilling revenues may not be fully realized.

At February 14, 2022, our contract backlog was approximately $6.47 billion.  This amount represents the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization, contract preparation, other incentive provisions or reimbursement revenues, which are not expected to be significant to our contract drilling revenues.  Our contract backlog includes amounts associated with our two contracted newbuild units that are currently under construction.  The contractual operating dayrate may be higher than the actual dayrate we ultimately receive or an alternative contractual dayrate, such as waiting on weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances.  The contractual operating dayrate may also be higher than the actual dayrate we ultimately receive due to a number of factors, including rig downtime or suspension of operations.  Several factors could cause rig downtime or a suspension of operations, including: equipment breakdowns and other unforeseen engineering problems, labor strikes and other work stoppages, shortages of material and skilled labor, surveys by government and maritime authorities, periodic classification surveys, severe weather or harsh operating conditions, and force majeure events.

In certain drilling contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.  Our contract backlog includes only firm commitments, which are represented by signed drilling contracts or, in some cases, other definitive agreements awaiting contract execution.  We may not be able to realize the full amount of our contract backlog due to events beyond our control.  In addition, some of our customers have experienced liquidity issues in the past, including some recently, and these liquidity issues could be experienced again if commodity prices decline for an extended period of time.  Liquidity issues and other market pressures could lead our customers to seek bankruptcy protection or to seek to repudiate, cancel or renegotiate these agreements for various reasons (see “—Our drilling contracts may be terminated due to a number of events, and, during depressed market conditions, our customers may seek to repudiate or renegotiate their contracts”).  Our inability to realize the full amount of our contract backlog may have an adverse effect on our financial position, results of operations or cash flows.

Our drilling contracts may be terminated due to a number of events, and, during depressed market conditions, our customers may seek to repudiate or renegotiate their contracts.

Certain of our drilling contracts with customers may be cancelable at the option of the customer upon payment of an early termination payment.  Such payments may not, however, fully compensate us for the loss of the contract.  Drilling contracts also customarily provide for either automatic termination or termination at the option of the customer, typically without the payment of any termination fee, under various circumstances such as non-performance, as a result of significant downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events, many of which are beyond our control.  Certain customers who seek to terminate our drilling contracts may attempt to defeat or circumvent our protections against certain liabilities.  Our customers’ ability to perform their obligations under their drilling contracts, including their ability to fulfill their indemnity obligations to us, may also be negatively impacted by an economic downturn.  Our customers, which include national energy companies, often have significant bargaining leverage over us.  If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated on terms that are not as favorable as current terms, it could adversely affect our financial position, results of operations or cash flows.

During periods of depressed market conditions, such as we have recently experienced, we are subject to an increased counterparty risk, as our customers may seek to repudiate their contracts, including through claims of non-performance in order to reduce their capital expenditures.  Our customers may no longer need a drilling rig that is currently under contract or may be able to obtain a comparable drilling rig at a lower dayrate.  We have experienced, and are at continued risk of experiencing, early contract terminations when there is a weak commodity price environment.  The ability of each of our counterparties to perform its obligations under a contract with us, including indemnity obligations, will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the offshore drilling industry, prevailing prices for oil and natural gas, the overall financial condition of the

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counterparty, the dayrates received and the level of expenditures necessary to maintain drilling activities.  Should a counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have an adverse effect on our business and on our financial position, results of operations or cash flows.

We must make substantial capital and operating expenditures to reactivate our stacked or idle fleet and to maintain our active fleet, and we may be required to make significant capital expenditures to maintain our competitiveness and to comply with laws and applicable regulations and standards of governmental authorities and organizations.

We must make substantial capital and operating expenditures to maintain our active fleet or to reactivate our stacked or idle fleet.  These expenditures could increase as a result of changes in the cost of labor and materials, requirements of customers, the size of our fleet, the cost of replacement parts for existing rigs, the geographic location of the rigs and the length of drilling contracts.  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 and to achieve our commitment to reduce our greenhouse gas emission intensity.  Changes in governmental regulations, including environmental requirements, and changes in safety or other equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may cause our capital expenditures to increase or require us to make additional unforeseen capital expenditures.  As a result of these factors, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment.  In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives.

If we are unable to fund capital expenditures with our cash flows from operations or proceeds from sales of non-strategic assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities, or additional financing arrangements with banks or other capital providers.  Our ability to access the capital markets may be limited by our financial condition at the time, perceptions of us or our industry, by changes in laws and regulations or interpretation thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.  If we raise funds by issuing equity securities or other securities that are convertible into equity securities, existing shareholders may experience dilution.  Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business and on our financial position, results of operations and cash flows.

Public health threats have had, and may continue to have, significant adverse consequences for general economic, financial and business conditions, as well as for our business and operations.

Public health threats, pandemics and epidemics, such as the outbreak of COVID-19, including new variants therof, severe influenza, other coronaviruses and other highly communicable viruses or diseases, have impacted and may continue to impact our operations directly or indirectly, including by disrupting the operations of our business partners, suppliers and customers in ways that adversely impact our operations.  For instance, the outbreak of COVID-19 and its development into a pandemic in March 2020 resulted in various actions by governmental authorities around the world designed to prevent or reduce the spread of COVID-19, such as imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions.  In addition, companies and individuals seeking to curtail the spread of COVID-19 have taken certain cautionary measures, such as certain companies requiring employees to work remotely, suspending or curtailing all non-essential travel for employees, and discouraging employee attendance at in-person work-related meetings, as well as individuals voluntarily social distancing and self-quarantining.  While many of the restrictions and measures initially implemented during 2020 have since been softened or lifted in varying degrees in different locations around the world, and the manufacture and distribution of COVID-19 vaccines during 2021 aided to initiate an economic recovery from the pandemic, the uncertainty regarding new potential virus variants and the success of any these vaccines may in the future adversely affect global economic activity or prompt the re-imposition of certain restrictions and measures.  Increases in COVID-19 cases, such as recently developed as new variants emerged, may result in significantly reduced economic activity, even if not required by governmental authorities, particularly in affected areas, which could result in a sharp reduction in the demand for oil and a decline in oil prices as occurred during 2020.

We continue to experience increased costs and inefficiencies as a result of the comprehensive precautionary measures we continue to take to help minimize the risk of COVID-19 impacts to our business, employees, customers, suppliers and the communities in which we operate, including testing employees for COVID-19 prior to transport offshore to a rig and quarantining any operational employee, where appropriate, who have shown signs of COVID-19, regardless of whether such employee has been confirmed to be infected, and we also have experienced increased costs as a result of increasing our pools of employees that are available to substitute for employees who are not able to travel to a rig.  We cannot guarantee that any precautionary measures will be effective in preventing either an outbreak of COVID-19 on one or more of our rigs or other adverse effects related to COVID-19.  To the extent an outbreak of COVID-19 develops on one or more of our rigs, we may have to temporarily shut down operations of such rig or rigs, which could result in significant downtime or contract termination and have substantial adverse consequences for our business and results of operations.  In addition, most of our non-operational employees continue to work remotely a substantial majority of their time, which increases various operational risks.  For instance, working remotely may increase the 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.

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Many governmental authorities across the globe implemented at various times during the COVID-19 pandemic travel restrictions and mandatory quarantine measures to prevent or reduce the spread of COVID-19, and in complying with such governmental actions, we have experienced, and expect to continue to experience, increased difficulties, delays and costs in moving our personnel in and out of, and to work in, the various jurisdictions in which we operate.  We may be unable to pass along these increased costs to our customers.  Additionally, disruptions to or restrictions on the ability of our suppliers, manufacturers and service providers to supply parts, equipment or services in the jurisdictions in which we operate or to progress the construction of our newbuild projects, whether as a result of government actions, labor shortages, the inability to source parts or equipment from affected locations, or other effects related to the COVID-19 outbreak, may have significant adverse consequences on our ability to meet our commitments to customers, including by increasing our operating costs and increasing the risk of rig downtime and could result in contract terminations.

Concerns over the prolonged negative effects of the COVID-19 outbreak on economic and business prospects across the world, including as a result of new variants of the virus, have also contributed to oil price volatility and uncertainty regarding the outlook for the global economy.  Such conditions have resulted in, and may continue to result in, reductions to our customers’ drilling and production expenditures and delays or cancellations of projects, thus decreasing demand for our services, and an increased risk that our customers may seek price reductions or more favorable economic terms for our services, terminate our contracts or that we may be required to idle, stack or retire more of our rigs.  Additionally, any early termination payment made in connection with an early contract termination may not fully compensate us for the loss of the contract.  Accordingly, the actual amount of revenues earned may be substantially lower than the reported contract backlog.  To the extent our suppliers experience a deterioration in financial condition or operational capability as a result of such depressed market and industry conditions or we or other suppliers incur delays in moving personnel to and from drilling rigs, we may experience disruptions in supply, which could increase our operating costs and increase rig downtime.  The occurrence of any such events with respect to our customers, contracts or suppliers in certain cases has had, and may continue to have, significant adverse consequences for our business and financial position.

The magnitude and duration of potential social, economic and labor instability resulting from the COVID-19 outbreak, including the speed at which national economies can recover, or whether any recovery will ultimately experience a reversal or other setbacks, are uncertain and cannot be estimated as such effects depend on future events that are largely out of our control.  The ultimate extent of the impact of COVID-19 and its variants on our business and financial position depend largely on future developments, including the duration, spread or containment of the outbreak, particularly within the geographic locations where we operate, and the related impact on overall economic activity, all of which are highly uncertain.  We are unable to predict the timing or impact of any such restructurings, if completed, on the capital structure and competitive dynamics among offshore drilling companies.

Public and investor sentiment towards climate change, fossil fuels and other esg matters could adversely affect our business, cost of capital and the price of our stock and other securities.

Changing public sentiment concerning fossil fuels, aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, has prompted efforts to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies.  These efforts have recently intensified, as demonstrated by the State of New York’s December 2020 announcement that it will be divesting the state’s Common Retirement Fund from fossil fuels.  If this or similar divestment efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.

Members of the investment community are also increasing their focus on environmental, social and governance (“ESG”) practices and disclosures, including practices and disclosures related to greenhouse gases and climate change, in the energy industry in particular, and diversity and inclusion initiatives and governance standards among public companies more generally.  As a result, we may face increasing pressure regarding our ESG disclosures and practices.  Additionally, members of the investment community may screen companies such as ours for ESG sustainability performance before investing in our stock.  Over the past few years there has also been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG investments.  As a result, there has been a proliferation of ESG focused investment funds seeking ESG oriented investment products.  If we or our securities are unable to meet the sustainability ESG standards or investment criteria set by these investors and funds, we may lose investors or investors may allocate a portion of their capital away from us, our cost of capital may increase, our stock price and the price of our publicly traded debt securities may be negatively impacted and our reputation may also be negatively affected.

We rely heavily on a relatively small number of customers and the loss of a significant customer or a dispute that leads to the loss of a customer could have an adverse effect on our business.

We engage in offshore drilling services for most of the leading integrated energy companies or their affiliates, as well as for many government-owned or government-controlled energy companies and other independent energy companies.  For the year ended December 31, 2021, our most significant customers were Shell and Equinor, representing approximately 31 percent and 30 percent, respectively, of our consolidated operating revenues.  As of February 14, 2022, the customers with the most significant aggregate amount of contract backlog associated with our drilling contracts were Shell, Equinor and Chevron, representing approximately 54 percent, 16 percent and 15 percent, respectively, of our total contract backlog.  The loss of any of these customers or another significant customer, or a decline in payments under any of our drilling contracts, could, at least in the short term, have an adverse effect on our business.

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Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues and are affected by many factors, including inflation.  Costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned.  In addition, should our rigs incur unplanned downtime while on contract or idle time between drilling contracts, we will not always reduce the staff on those rigs because we could use the crew to prepare the rig for its next contract.  During times of reduced activity, reductions in costs may not be immediate because portions of the crew may be required to prepare rigs for stacking, after which time the crew members may be reassigned to active rigs or released.  As our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly.  In general, labor costs increase primarily due to higher salary levels and inflation.  Equipment maintenance costs fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment, and these costs could increase for short or extended periods as a result of regulatory or customer requirements that raise maintenance standards above historical levels.  The amount of contract preparation and reactivation costs vary based on the scope and length of the contract preparation or reactivation project, and the recognition of such costs varies depending on the duration of the firm contractual period and other contract terms.

Certain of our drilling contracts are partially payable in local currency.  The amounts, if any, of local currency received under these drilling contracts may exceed our local currency needs to pay local operating and maintenance costs, leading to an accumulation of excess local currency balances, which, in certain instances, may be subject to either restrictions or other difficulties in converting to U.S. dollars, our functional currency, or to other currencies of the locations where we operate.  Excess amounts of local currency may also be exposed to the risk of currency exchange losses.

Our business involves numerous operating hazards, and our insurance and indemnities from our customers may not be adequate to cover potential losses from our operations.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as, blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, craterings, fires, explosions and pollution.  Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and other parties.  These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental or natural resource damage, claims by third parties or customers and suspension of operations.  Our offshore fleet is also subject to hazards inherent in marine operations, either while on site or during mobilization, such as capsizing, sinking, grounding, collision, piracy, damage from severe weather and marine life infestations.

The South China Sea, the Northwest Coast of Australia and the U.S. Gulf of Mexico are areas subject to typhoons, hurricanes or other extreme weather conditions on a relatively frequent basis, and our drilling rigs in these regions may be exposed to damage or total loss by these storms, some of which may not be covered by insurance.  The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel.  Some experts believe global climate change could increase the frequency and severity of these extreme weather conditions.  Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages.  We customarily provide contract indemnity to our customers for certain claims that could be asserted by us relating to damage to or loss of our equipment, including rigs, and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment or natural resources could also result from our operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires.  We may also be subject to property damage, environmental indemnity and other claims by energy companies or other third parties.  Drilling involves certain risks associated with the loss of control of a well, such as blowout, cratering, the cost to regain control of or redrill the well and remediation of associated pollution.  Our customers may be unable or unwilling to indemnify us against such risks.  In addition, a court may decide that certain indemnities in our current or future drilling contracts are not enforceable.  The law generally considers contractual indemnity for criminal fines and penalties to be against public policy, and the enforceability of an indemnity as to other matters may be limited.

Our insurance policies and drilling contracts contain rights to indemnity that may not adequately cover our losses, and we do not have insurance coverage or rights to indemnity for all risks.  We have two main types of insurance coverage: (1) hull and machinery coverage for physical damage to our property and equipment and (2) excess liability coverage, which generally covers offshore risks, such as personal injury, third-party property claims, and third-party non-crew claims, including wreck removal and pollution.  We generally have no hull and machinery insurance coverage for damages caused by named storms in the U.S. Gulf of Mexico.  We maintain per occurrence deductibles that generally range up to $10 million for various third-party liabilities, and we self-insure $50 million of the $750 million excess liability coverage through our wholly owned captive insurance company.  We also retain the risk for any liability that exceeds our excess liability coverage.  However, pollution and environmental risks generally are not completely insurable.

If a significant accident or other event occurs that is not fully covered by our insurance or by an enforceable or recoverable indemnity, the occurrence could adversely affect our financial position, results of operations or cash flows.  The amount of our insurance may also be less than the related impact on enterprise value after a loss.  Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations.  Our coverage includes annual aggregate policy limits.  As a result, we generally retain the risk for any losses in excess of these limits.  We generally do not carry insurance for loss of revenue, and

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certain other claims may also not be reimbursed by insurance carriers.  Any such lack of reimbursement may cause us to incur substantial costs.  In addition, we could decide to retain more risk in the future, resulting in higher risk of losses, which could be material.  Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable or be able to obtain insurance against certain risks.

Failure to recruit and retain key personnel could hurt our operations.

We depend on the continuing efforts of key members of our management, as well as other highly skilled personnel, to operate and provide technical services and support for our business worldwide.  Historically, competition for the personnel required for drilling operations has intensified as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover.  We may experience a reduction in the experience level of our personnel as a result of any increased turnover and ongoing staff reduction initiatives, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs.  If increased competition for qualified personnel were to intensify in the future we may experience increases in costs or limits on operations.

Our labor costs and the operating restrictions under which we operate could increase as a result of collective bargaining negotiations and additional unionization efforts.

Approximately 42 percent of our total workforce, working primarily in Norway, Brazil and the U.K., are represented by, and some of our contracted labor work is subject to, collective bargaining agreements, substantially all of which are subject to annual salary negotiation.  Negotiations over annual salary or other labor matters could result in higher personnel or other costs or increased operational restrictions or disruptions.  The outcome of any such negotiation generally affects the market for all offshore employees, not only the union members.  A failure to reach an agreement on certain key issues could result in strikes, lockouts, or other work stoppages.  Legislation has been introduced in the U.S. Congress that could encourage additional unionization efforts in the U.S., as well as increase the chances that such efforts succeed.  Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs and operating restrictions.

Our shipyard projects and operations are subject to delays and cost overruns.

As of February 14 2022, we had under construction two ultra-deepwater drillships.  We also have a variety of other more limited shipyard projects at any given time.  These shipyard projects are subject to the risks of delay or cost overruns inherent in any such construction project resulting from numerous factors, including the following:

◾ complications arising from pandemics and epidemics, such as COVID-19, severe influenza, other coronaviruses and other highly communicable viruses or diseases, and associated government orders in the country where the rigs are being constructed or serviced and elsewhere;

◾ shipyard availability, failures and difficulties;

◾ shortages of equipment, materials or skilled labor;

◾ failure or delayed deliveries of significant materials or equipment for various reasons, including due to supplier shortages, constraints, disruption or quality issues;

◾ design and engineering problems, including those relating to the commissioning of newly designed equipment;

◾ latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;

◾ unanticipated actual or purported change orders;

◾ disputes with shipyards and suppliers;

◾ availability of suppliers to recertify equipment for enhanced regulations;

◾ strikes, labor disputes and work stoppages;

◾ customer acceptance delays or delays in providing customer-supplied engineering, approvals or equipment;

◾ adverse weather conditions, including damage caused by such conditions;

◾ terrorist acts, war, piracy and civil unrest;

◾ unanticipated cost increases; and

◾ difficulty in obtaining necessary permits or approvals.

These factors may contribute to cost variations and delays in the delivery of our newbuild units and other rigs undergoing shipyard projects.  Cost variations may result in, among other things, disputes with the shipyards that construct or service our drilling units.  In addition, delayed delivery of our newbuild units or other rigs undergoing shipyard projects would impact contract commencement, resulting in a loss of revenues we could earn, and may also cause customers to terminate or shorten the term of the drilling contract for the rig pursuant to applicable late delivery clauses.  In the event of termination of any of these drilling contracts, we may not be able to secure a replacement contract on as favorable terms, if at all.

Our operations also rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet.  We also rely on the supply of ancillary services, including supply boats and helicopters.  Our reliance on our suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to volatility in the quality, prices and availability of such items.  Certain parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider.  A disruption in the deliveries from our suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment or ancillary services could adversely

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affect our ability to meet our commitments to customers, adversely impact our operations, increase our operating costs and result in increases in rig downtime and delays in the repair and maintenance of our fleet.

As part of our business strategies, We may pursue opportunities to strengthen and broaden our business 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 strengthen or broaden our business.  Any such transaction would be evaluated on a case-by-case basis, and the consummation thereof would be dependent upon several factors, including identifying suitable companies, businesses or assets that align with our business strategies, reaching agreement with the potential counterparties on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions.  These transactions involve various risks, including among others, (i) difficulties related to integrating or managing applicable parts of an acquired business or joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing, (ii) diversion of management's attention from day-to-day operations, (iii) failure to realize anticipated benefits, such as cost savings, revenue enhancements or strengthening or broadening our business, (iv) potentially substantial transaction costs associated with acquisitions, joint ventures or investments if we or a transaction counterparty seeks to exit or terminate an interest in the joint venture or investment, and (v) potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time of such transaction is consummated.

Failure to effectively and timely address the transition to renewable or other alternative energy sources could adversely affect our business, results of operations and cash flows.

Our long-term success depends on our ability to effectively address the transition to renewable and other alternative energy sources, which may require adapting certain parts or our operations to potentially changing government requirements, customer preferences and to a potentially changing and broader customer base, as well as engaging with existing and potential customers and suppliers to develop or implement solutions designed to reduce or decarbonize oil and gas operations, or to advance renewable and other alternative energy sources.  If the energy transition landscape changes faster than anticipated or in a manner that we do not anticipate, demand for our services could be adversely affected.  Furthermore, if we fail or are perceived to not effectively implement an energy transition strategy, or if investors or financial institutions shift funding away from companies in fossil fuel-related industries, our access to capital or the market for our securities could be negatively impacted.

Our aspirations, goals, commitment targets and initiatives related to sustainability, including emissions reduction, and our public statements and disclosures regarding them, expose us to numerous risks.

We have developed, and will continue to develop and set, goals, targets, and other objectives related to sustainability matters, including our commitment target to reduce our greenhouse gas emissions.  Statements related to these goals, commitment targets and objectives reflect our current intentions and do not constitute a guarantee that they will be achieved.  Our efforts to research, establish, accomplish, and accurately report on these goals, commitment targets, and other objectives expose us to numerous operational, reputational, financial, legal, and other risks.  Our ability to achieve any stated goal, commitment target, or objective, including with respect to emissions intensity reduction, is subject to numerous factors and conditions, some of which are outside of our control.

Our business may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, commitment targets, and other objectives that we announce, and our methodologies and timelines for pursuing them.  If our sustainability assumptions or practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected.  Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.

Risks related to our indebtedness

We have a substantial amount of debt, including secured debt, and we may lose the ability to obtain future financing and suffer competitive disadvantages.

At December 31, 2021 and 2020, our total debt was $7.17 billion and $7.81 billion, respectively, of which $2.30 billion and $2.77 billion, respectively, was secured.  We have a bank credit agreement, as amended, that established a $1.33 billion secured revolving credit facility (the “Secured Credit Facility”), which is currently undrawn, the borrowings under which would be secured.  This substantial level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:

◾ we may be unable to obtain financing in the future to refinance our existing debt or for working capital, capital expenditures, acquisitions, debt service requirements, distributions, share repurchases, or other purposes;

◾ we may be unable to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;

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◾ we could become more vulnerable to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness, some of which bears interest at variable rates;

◾ we may be unable to meet financial ratios in the agreements governing certain of our debt and finance lease or satisfy certain other covenants and conditions included in our debt agreements, which could result in our inability to meet requirements for borrowings under our credit agreement or a default under these agreements, impose restrictions with respect to our access to certain of our capital, and trigger cross default provisions in our other debt instruments;

◾ if we default under the terms of our secured financing arrangements, the secured debtholders may, among other things, foreclose on the collateral securing the debt, including the applicable drilling units;

◾ we may be unable to obtain new investment or financing given recent environmental, social and governance influenced trends among many financial intermediaries, investors and other capital markets participants in reducing, or ceasing, lending to, or investing in, companies that operate in industries with higher perceived environmental exposure; and

◾ we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our less levered competitors.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources and uses of liquidity.”

Credit rating agencies have rated our debt below investment grade, which could limit our access to capital and have an adverse effect on our business and financial condition.

The ratings assigned to our debt securities by certain credit rating agencies (our “Debt Ratings”) are below investment grade.  Our Debt Ratings could have adverse consequences for our business and future prospects and could cause the following:

◾ limitations on our ability to access debt markets, including for the purpose of refinancing our existing debt and replacing or extending our Secured Credit Facility;

◾ less favorable terms and conditions on any refinancing arrangements, debt issuances or bank credit agreements, some of which could require collateral and restrict, among other things, our ability to pay distributions or repurchase shares;

◾ increases to certain fees under our Secured Credit Facility and interest rates under indentures governing certain of our senior notes, which in the case of the 3.80% senior notes due October 2022 and the 7.35% senior notes due December 2041, have reached the maximum rate increase of 2 percent pursuant to the related indentures due to the downgrades of certain credit rating agencies;

◾ reduced willingness of current and prospective customers, suppliers and creditors to transact business with us;

◾ requirements from creditors, suppliers or customers for additional insurance, guarantees and collateral;

◾ limitations on our access to bank and third-party guarantees, surety bonds and letters of credit; and

◾ reductions to or eliminations of the level of credit suppliers and financial institutions may provide through payment terms or intraday funding when dealing with us thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay debt balances.

Our Debt Ratings have caused some of the effects listed above, and any further downgrades may cause or exacerbate, any of the effects listed above and could have an adverse effect on our business and financial condition.

Worldwide financial, economic and political conditions could restrict our ability to access the capital markets, reduce our flexibility to react to changing economic and business conditions and reduce demand for our services.

Worldwide financial and economic conditions could restrict our ability to access the capital markets at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions.  Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us.  If economic conditions preclude or limit financing from banking institutions participating in our credit facilities, we may not be able to obtain similar financing from other institutions.  A slowdown in economic activity could further reduce worldwide demand for energy and extend or worsen the recovery from low oil and natural gas prices.  These potential developments, or market perceptions concerning these and related issues, could adversely affect our financial position, results of operations or cash flows.  In addition, turmoil and hostilities in the Middle East, North Africa and other geographic areas and countries present incremental risk.  An extended period of negative outlook for the world economy could further reduce the overall demand for oil and natural gas and for our services.  A further decline in oil and natural gas prices or an extension of the current low oil and natural gas prices could reduce demand for our drilling services and have an adverse effect on our financial position, results of operations or cash flows.

Risks related to laws, regulations and governmental compliance

Impact of increasingly stringent environmental and safety laws and our compliance with or breach of such laws can be costly, expose us to liability and could limit our operations.

Our business is affected by laws and regulations relating to the energy industry and the environment and safety, including international conventions and treaties, and regional, national, state, and local laws and regulations.  Our business also depends on demand for services from the oil and gas exploration and production industry, and, accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail, delay or impose additional compliance costs and obligations related to the exploration and development drilling for oil and gas.  Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of environmental or safety concerns.  In addition, compliance with environmental and safety laws, regulations and standards, where applicable, may require us to make significant capital expenditures, such as the installation of costly equipment or

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implementation of operational changes, and may affect the resale values or useful lives of our rigs.  We may also incur additional costs in order to comply with other existing and future regulatory obligations or industry standards, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and maintenance of insurance coverage or other financial assurance of our ability to address pollution incidents.  In the last decade, enhanced governmental safety and environmental requirements applicable to our operations were adopted by U.S. federal agencies for drilling in the U.S. Gulf of Mexico that have caused, and may in the future cause, operators to have difficulties obtaining drilling permits in the U.S. Gulf of Mexico.  In addition, the oil and gas industry has adopted equipment and operating standards, such as the American Petroleum Institute Standard 53, related to the installation and testing of well control equipment.  A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations.  Additionally, our customers may elect to voluntarily comply with any non-mandatory laws, regulations or other standards.  Any such safety, environmental and other regulatory restrictions or standards, including voluntary customer compliance with respect thereto, could decrease, disrupt or delay operations, decrease demand for offshore drilling services, increase operating costs and compliance costs or penalties, increase out-of-service time, decrease dayrates, or reduce the area of operations for drilling rigs in the U.S. and non-U.S. offshore areas.  Any such effects could have an adverse effect on our financial position, results of operations or cash flows.

To the extent new laws are enacted, existing laws are changed or other governmental actions are taken that prohibit or restrict offshore drilling or impose additional environmental protection and safety requirements that result in increased costs to the oil and gas industry, in general, or the offshore drilling industry, in particular, our business or prospects could be materially adversely affected.  The operation of our drilling rigs will require certain governmental approvals, some of which may involve public hearings and costly undertakings on our part.  We may not obtain such approvals or such approvals may not be obtained in a timely manner.  If we fail to timely secure the necessary governmental approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.  The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling or production of oil and gas and compliance with any such new or amended legislation or regulations could have an adverse effect on our business or on our financial position, results of operations or cash flows.

As a contract driller with operations in certain offshore areas, we may be liable for damages and costs incurred in connection with oil spills or disposal of wastes related to those operations, and we may also be subject to significant fines and other liabilities in connection with spills.  For example, an oil spill could result in significant liability, including fines, penalties and criminal liability and remediation, restoration or compensation costs for environmental or natural resource damages, as well as third-party damages, to the extent that the contractual indemnification provisions in our drilling contracts are not enforceable or otherwise sufficient, or if our customers are unwilling or unable to contractually indemnify us against these risks.  Additionally, we may not be able to obtain such indemnities in our future drilling contracts, and our customers may not have the financial capability to fulfill their contractual obligations to us.  Also, these indemnities may be held to be unenforceable in certain jurisdictions, as a result of public policy or for other reasons.  Environmental and safety laws and regulations protecting the environment have become increasingly stringent and may in some cases impose strict liability on facility or vessel owners or operators, rendering a person liable for environmental damage without regard to negligence.  These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time they were performed.  The application of these requirements or the adoption of new requirements or measures could have an adverse effect on our financial position, results of operations or cash flows.

Regulatory and various other risks, including litigation, associated with greenhouse gases and climate change could have an adverse impact on our business and demand for our services.

Scientific studies have suggested that emissions of certain gases, including greenhouse gases, such as carbon dioxide and methane, contribute to warming of the earth’s atmosphere and other climatic changes.  In response to such studies, the issue of climate change and the effect of greenhouse gas emissions, in particular emissions from the fossil fuel industry, has attracted considerable attention worldwide.  The attention to climate change has led, and we expect it to continue to lead, to additional regulations designed to reduce greenhouse gas emissions domestically and internationally.  Such attention could also result in other adverse impacts for the oil and gas industry, including further restrictions or bans imposed by lawmakers, lawsuits by governments or third-parties seeking recoveries for damages resulting from the combustion of fuels that may contribute to climate change effects, or reduced interest from investors if they elect in the future to shift some or all of their investments to non-fossil fuel related sectors.  To the extent financial markets view climate change and greenhouse emissions as a financial risk, this could negatively impact our cost of or access to capital.  Because our business depends on the level of activity in the oil and gas industry, existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, or related political, litigation or financial risks, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas or limit drilling opportunities.  In addition, such laws, regulations, treaties or international agreements or related risks could result in increased compliance costs or additional operating restrictions, which may have an adverse effect on our business.  Further, some experts believe global climate change could increase the frequency and severity of extreme weather conditions, the impacts of which could interfere with our operations, cause damage to our equipment as well as cause other financial and operational impacts, including those that could result from any impact of such conditions on our customers.

We could also face increased climate-related litigation with respect to our operations both in the U.S. and around the world.  Governmental and other entities in various U.S. states, such as California and New York, have filed lawsuits against coal, gas oil and

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petroleum companies.  These suits allege damages as a result of climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories.  Similar lawsuits may be filed in other jurisdictions both in the U.S. and globally.  Though we are not currently a party to any such lawsuit, these suits present a high degree of uncertainty regarding the extent to which energy companies, including offshore drillers, face an increased risk of liability stemming from climate change, which risk would also adversely impact the oil and gas industry and impact demand for our services.

The global nature of our operations involves additional risks.

We operate in various regions throughout the world, which may expose us to political and other uncertainties, including risks of:

◾ terrorist acts, war, piracy and civil unrest;

◾ seizure, expropriation or nationalization of our equipment;

◾ expropriation or nationalization of our customers’ property;

◾ repudiation or nationalization of contracts;

◾ imposition of trade or immigration barriers;

◾ import-export quotas;

◾ wage and price controls;

◾ changes in law and regulatory requirements, including changes in interpretation and enforcement;

◾ involvement in judicial proceedings in unfavorable jurisdictions;

◾ damage to our equipment or violence directed at our employees, including kidnappings;

◾ complications associated with supplying, repairing and replacing equipment in remote locations;

◾ the inability to move income or capital; and

◾ currency exchange fluctuations and currency exchange restrictions, including exchange or similar controls that may limit our ability to convert local currency into U.S. dollars and transfer funds out of a local jurisdiction.

Our non-U.S. contract drilling operations are subject to various laws and regulations in certain countries in which we operate, including laws and regulations relating to the import and export, equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation and social contributions of offshore earnings and earnings of expatriate personnel.  We are also subject to the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”) and other U.S. and non-U.S. laws and regulations governing our international operations.  In addition, various state and municipal governments, universities and other investors have proposed or adopted divestment and other initiatives regarding investments including, with respect to state governments, by state retirement systems in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department.  Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets.  Investors could view any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our shares.

Governments in some countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries, including local content requirements for participating in tenders for certain drilling contracts.  Many governments favor or effectively require the awarding of drilling contracts to local contractors or require nonlocal contractors to employ citizens of, or purchase supplies from, a particular jurisdiction or require use of a local agent.  In addition, government action, including initiatives by OPEC, may continue to cause oil or gas price volatility.  In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work by major energy companies and may continue to do so.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations.  Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate.  Moreover, many countries, including the U.S., control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations.  Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities, and we are also subject to the U.S. anti-boycott law.

The laws and regulations concerning import and export activity, recordkeeping and reporting, import and export control and economic sanctions are complex and constantly changing.  These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations.  Ongoing economic challenges may increase some governments’ efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue.  Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes.  Shipping delays or denials could cause unscheduled operational downtime.

Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate.  Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits.  If we are not able to obtain visas and work permits for the employees we need to conduct our operations on a timely basis, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts.  If our customers cancel some of our drilling contracts, and we are unable to secure new drilling contracts on a timely basis and on substantially similar terms, it could have a material adverse effect on our business and on our financial position, results of operations or cash flows.

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Failure to comply with anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

The U.S. Foreign Corrupt Practices Act (“FCPA”), the U.K. Bribery Act 2010 (“Bribery Act”) and similar anti-bribery laws in other jurisdictions, generally prohibit companies and their intermediaries from making improper payments for the purpose of obtaining or retaining business.  We operate in many parts of the world that have experienced corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices.  If we are found to be liable for violations under the FCPA, the Bribery Act or other similar laws, either due to our acts or omissions or due to the acts or omissions of others, including our partners in our various joint ventures and of the current or former officers, directors or employees of any companies we have acquired, we could suffer from civil and criminal penalties or other sanctions, which could have a material adverse effect on our business or our financial position, results of operations or cash flows.  In addition, investors could negatively view potential violations, inquiries or allegations of misconduct under the FCPA, the Bribery Act or similar laws, which could adversely affect our reputation and the market for our shares.

We could also face fines, sanctions and other penalties from authorities in relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets.  Additionally, our business and results of operations could be adversely affected as a result of claims by customers, agents, shareholders, debt holders, other interest holders, current or former employees or other constituents of our company who, in connection with alleged or actual noncompliance with antibribery and related laws, may seek to impose penalties, seek remedies, terminate drilling contracts or take other actions adverse to our interests.  Our business and results of operations may be adversely affected if we are required to dedicate significant time and resources to investigate and resolve allegations of misconduct, regardless of the merit of such allegations.  Further, disclosure of the subject matter of any investigation could adversely affect our reputation and our ability to obtain new business with potential customers, to retain existing business with our current customers, to attract and retain employees and to access the capital markets.

We are subject to investigations and litigation that, if not resolved in our favor and not sufficiently insured against, could have a material adverse effect on us.

We are subject to a variety of disputes, investigations and litigation.  Certain of our subsidiaries are subject to and have been involved in litigation with certain of our customers and other constituents.  Certain of our subsidiaries are named as defendants in numerous lawsuits alleging personal grievances or injury, including as a result of exposure to asbestos or toxic fumes or resulting from other occupational diseases, such as silicosis, and various other medical issues that can remain undiscovered for a considerable amount of time.  Some of these subsidiaries that have been put on notice of potential liabilities have no assets.  Certain subsidiaries are subject to litigation relating to environmental damage.  Our patent for dual-activity technology has been successfully challenged in certain jurisdictions.  We are also subject to a number of significant tax disputes.  We cannot predict the outcome of these investigations and cases or the potential costs to resolve them.  Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent and policies may not be located.  Suits against non-asset-owning subsidiaries have and may in the future give rise to alter ego or successor-in-interest claims against us and our asset-owning subsidiaries to the extent a subsidiary is unable to pay a claim or insurance is not available or sufficient to cover the claims.  To the extent that one or more pending or future investigations or litigation matters is not resolved in our favor and is not covered by insurance, which could have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to cybersecurity risks and threats as well as increasing regulation of data privacy and security.

We depend on data and digital technologies to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees.  Our data protection measures and measures taken by our customers and vendors may not prevent unauthorized access of information technology systems, and when such unauthorized access occurs, we, our customers or vendors may not detect the incident in time to prevent harm or damage.  Threats to our information technology systems, and the systems of our customers and vendors, associated with cybersecurity risks and cyber-incidents or attacks continue to grow.  Such threats may derive from human error, fraud or malice, social engineering on the part of employees or third parties, or may result from accidental technological failure.  In addition, breaches to our systems and systems of our customers and vendors could go unnoticed for some period of time.  Risks associated with these threats include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss or ransom of intellectual property, proprietary information, personal identifiable information or customer and vendor data; disruption of our customers’ and vendors’ operations; misappropriation of assets; loss or damage to our customer and vendor data delivery systems; and increased costs to prevent, respond to or mitigate cybersecurity events.  A breach could also originate from, or compromise, our customers’ and vendors’ or other third-party networks outside of our control.  A breach may also result in legal claims or proceedings against us by our shareholders, employees, customers, vendors and governmental authorities, both U.S. and non-U.S.  If such a cyber-incident were to occur, it could have a material adverse effect on our business or on our financial position, results of operations or cash flows.

In addition, laws and regulations governing data privacy and the unauthorized disclosure of personal data and confidential information, including the European Union General Data Protection Regulation, the Data Protection Law, as revised, of the Cayman Islands, the General Data Protection Law of Brazil and the California Consumer Privacy Act, pose increasingly complex compliance challenges and potential to elevate our costs.  Any failure by us to comply with these laws and regulations, including as a result of a security or privacy

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breach, could result in significant penalties, litigation and liabilities for us.  Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services.

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 affect the markets for 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.  Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy or political or social unrest.  We have limited insurance for our assets providing coverage for physical damage losses resulting from certain risks, such as terrorist acts, piracy, vandalism, sabotage, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenues resulting from such risks.

Risks related to taxes

A change in tax laws, treaties or regulations, or their interpretation, of any country in which we have operations, are incorporated or are resident could result in a higher effective tax rate on our consolidated earnings and increase our cash tax payments.

We are subject to changes in applicable tax laws, treaties or regulations in the jurisdictions in which we operate and earn income, and such changes could include laws or policies directed toward companies organized in jurisdictions with low tax rates with the intent to increase the tax burden.  The Organization for Economic Co-operation and Development, for example, issued its action plan of tax reform measures that called for member states to take action to prevent base erosion and profit shifting.  Some of these measures impact transfer pricing, requirements to qualify for tax treaty benefits, and the definition of permanent establishments depending on each jurisdiction’s adoption and interpretation of such proposals.  Respective countries, including Switzerland, have adopted various measures into their own tax laws.  In addition, the EU has issued Anti-Tax Avoidance Directives and proposed directives that required or require member states to adopt specific tax reform measures, some of which relate to a 15 percent minimum tax.  Other tax jurisdictions in which we operate may consider implementing similar measures.  Any material change to tax laws, treaties, regulations or policies, their interpretation or application, or the adoption of new interpretations of existing laws and rulings, in any of the jurisdictions in which we operate, are incorporated or resident, could result in a higher effective tax rate on our worldwide earnings and such change could have a significant adverse effect on our financial position, results of operations or cash flows.

A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries could result in a higher effective tax rate on our consolidated earnings and increase our cash tax payments.

We are subject to tax laws, treaties and regulations in the countries in which we operate and earn income.  Our income taxes are based on the applicable tax laws and tax rates in effect in the countries in which we operate and earn income as well as upon our operating structures in these countries.  Our income tax returns are subject to review and examination in these jurisdictions, and we do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority.  If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.  For example, we believe that neither we nor our non-U.S. subsidiaries, other than those that report a U.S. trade or business or a U.S. permanent establishment, were or are engaged in a trade or business in the U.S. or, if applicable, maintained or maintain a permanent establishment in the U.S.  The determination of the aforementioned, among other things, involves considerable uncertainty.  If the U.S. Internal Revenue Service (the “IRS”) were to disagree, then we could be subject to additional U.S. corporate income and branch profits taxes on the portion of our earnings effectively connected to such U.S. business or, if applicable, attributable to such U.S. permanent establishment during the period in which this was considered to have occurred.  If this occurs, our effective tax rate on worldwide earnings for that period could increase substantially, we could be subject to assessments in previously filed returns that remain open to audit and our earnings and cash flows from operations for that period could be adversely affected.

U.S. tax authorities could treat us as a passive foreign investment company, which would have adverse U.S. federal income tax consequences to U.S. shareholders.

A foreign corporation will be treated as a passive foreign investment company (“PFIC”) for U.S. federal income tax purposes if either (1) at least 75 percent of its gross income for any taxable year consists of certain types of passive income or (2) at least 50 percent of the average value of the corporation's assets produce or are held for the production of those types of passive income.  For purposes of these tests, passive income includes dividends, interest and gains from the sale or exchange of investment property and certain rents and royalties, but does not include income derived from performing services.  We believe that we have not been and will not be a PFIC with respect to any taxable year.  Our income from offshore contract drilling services should be treated as services income for purposes of determining whether

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we are a PFIC.  Accordingly, we believe that our income from our offshore contract drilling services should not constitute passive income, and the assets that we own and operate in connection with the production of that income should not constitute passive assets.  There is significant legal authority supporting this position, including statutory provisions, legislative history, case law and IRS pronouncements concerning the characterization, for other tax purposes, of income derived from services where a substantial component of such income is attributable to the value of the property or equipment used in connection with providing such services.  However, a prior case and an IRS pronouncement that relies on such case characterize income from time chartering of vessels as rental income rather than services income for other tax purposes.  The IRS has subsequently formally announced that it does not agree with the decision in that case.  Moreover, we believe that the terms of the time charters in the prior case differ in material respects from the terms of our drilling contracts with customers.  However, no assurance can be given that the IRS or a court will accept our position, and there is a risk that the IRS or a court could determine that we are a PFIC.

If we were treated as a PFIC for any taxable year, our U.S. shareholders would face adverse U.S. tax consequences.  Under the PFIC rules, unless a shareholder makes certain elections available under the Internal Revenue Code of 1986, as amended, which elections could themselves have adverse consequences for the shareholder, the shareholder could be required to pay U.S. federal income tax at the highest applicable income tax rates on ordinary income upon the receipt of excess distributions, as defined for U.S. tax purposes, and upon any gain from the disposition of our shares, plus interest on such amounts, as if such excess distribution or gain had been recognized ratably over the shareholder’s holding period of our shares.  Additionally, under applicable statutory provisions, the preferential tax rate on qualified dividend income, which applies to dividends paid to non-corporate shareholders, does not apply to dividends paid by a foreign corporation if the foreign corporation is a PFIC for the taxable year in which the dividend is paid or the preceding taxable year.

Risks related to our jurisdiction of organization and governing documents

As a Swiss corporation, our flexibility may be limited with respect to certain aspects of capital management AND swift implementation of certain initiatives or strategies.

Under Swiss law, our shareholders may approve an authorized share capital that allows the board of directors to issue new shares without additional shareholder approval within a period of up to two years and for up to a maximum of 50 percent of a company’s issued share capital.  The authorized share capital approved by our shareholders at the May 2021 annual general meeting will expire on May 27, 2023.  Our currently available authorized share capital is limited to approximately 22 percent of our issued share capital as of February 14, 2022.  Accordingly, shareholders at our annual general meeting in May 2022 may be requested to approve a renewal and an increase in authorized share capital.  Subject to certain exceptions, Swiss law also grants preemptive rights to existing shareholders to subscribe for new issuances of shares.  Further, Swiss law does not provide as much flexibility in the various terms that can attach to different classes of shares as the laws of some other jurisdictions.  Swiss law also reserves for shareholder approval certain corporate actions, such as approval of dividends, over which a board of directors would have authority in some other jurisdictions.  These Swiss law requirements relating to our capital management may limit our flexibility to swiftly implement certain initiatives or strategies, and situations may arise where greater flexibility would have provided substantial benefits to our shareholders.

We are required, from time to time, to evaluate the carrying amount of our investments in affiliates, as presented on our Swiss standalone balance sheet.  If we determine that the carrying amount of any such investment exceeds its fair value, we may conclude that such investment is impaired.  Any recognized loss associated with such a non-cash impairment could result in our net assets no longer covering our statutory share capital and statutory capital reserves.  Under Swiss law, if our net assets cover less than 50 percent of our statutory share capital and statutory capital reserves, the board of directors must convene a general meeting of shareholders and propose measures to remedy such a capital loss.  Appropriate measures depend on the relevant circumstances and the magnitude of the recognized loss and may include seeking shareholder approval for offsetting the aggregate loss, or a portion thereof, with our statutory capital reserves, including qualifying additional paid-in capital otherwise available for distributions to shareholders, or raising new equity.  Depending on the circumstances, we may also need to use qualifying additional paid-in capital available for distributions in order to reduce our accumulated net loss and such use might reduce our ability to make distributions without subjecting our shareholders to Swiss withholding tax.

Distributions to shareholders in the form of a par value reduction and dividend distributions out of qualifying additional paid-in capital are currently not subject to the 35 percent Swiss federal withholding tax.  However, the Swiss withholding tax rules could be changed in the future, and any such change may adversely affect us or our shareholders.  In addition, over the long term, the amount of par value available for us to use for par value reductions or the amount of qualifying additional paid-in capital available for us to pay out as distributions is limited.  If we are unable to make a distribution through a reduction in par value, or out of qualifying additional paid-in capital as shown on Transocean Ltd.’s standalone Swiss statutory financial statements, we may not be able to make distributions without subjecting our shareholders to Swiss withholding taxes.

Under Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to a 35 percent Swiss withholding tax based on the difference between the repurchase price and the related amount of par value and the related amount of qualifying additional paid-in capital, if any.  At our 2009 annual general meeting, our shareholders approved the repurchase of up to CHF 3.5 billion of our shares for cancellation under the share repurchase program.  If we repurchase shares, we expect to use an alternative procedure pursuant to which we repurchase shares via a “virtual second trading line” from market players, such as banks and institutional investors, who are generally entitled to receive a full refund of the Swiss withholding tax.  The use of such “virtual second trading line” with respect to share repurchase programs is subject to the approval of the competent Swiss tax and other authorities.  We may not be

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able to repurchase as many shares as we would like to repurchase for purposes of capital reduction on the “virtual second trading line” without subjecting the selling shareholders to Swiss withholding taxes.

We are subject to anti-takeover provisions.

Our articles of association and Swiss law contain provisions that could prevent or delay an acquisition of the company by means of a tender offer, a proxy contest or otherwise.  Actions taken under such provisions may adversely affect prevailing market prices for our shares, and could, among other things:

◾ provide that the board of directors is authorized, subject to obtaining shareholder approval every two years, at any time during a maximum two-year period, which under our current authorized share capital will expire on May 27, 2023, to issue a specified number of shares, which under our current authorized share capital is approximately 22 percent of the share capital registered in the commercial register as of February 14, 2022, and to limit or withdraw the preemptive rights of existing shareholders in various circumstances;

◾ provide for a conditional share capital that authorizes the issuance of additional shares up to a maximum amount of approximately 20 percent of the share capital registered in the commercial register as of February 14, 2022, without obtaining additional shareholder approval through: (1) the exercise of conversion, exchange, option, warrant or similar rights for the subscription of shares granted in connection with bonds, options, warrants or other securities newly or already issued in national or international capital markets or new or already existing contractual obligations by or of any of our subsidiaries; or (2) in connection with the issuance of shares, options or other share-based awards;

◾ provide that any shareholder who wishes to propose any business or to nominate a person or persons for election as director at any annual meeting may only do so if we are given advance notice;

◾ provide that directors can be removed from office only by the affirmative vote of the holders of at least 66 2/3 percent of the shares entitled to vote;

◾ provide that a merger or demerger transaction requires the affirmative vote of the holders of at least 66 2/3 percent of the shares represented at the meeting and provide for the possibility of a so-called cash-out or squeeze-out merger if the acquirer controls 90 percent of the outstanding shares entitled to vote at the meeting;

◾ provide that any action required or permitted to be taken by the holders of shares must be taken at a duly called annual or extraordinary general meeting of shareholders;

◾ limit the ability of our shareholders to amend or repeal some provisions of our articles of association; and

◾limit transactions between us and an “interested shareholder,” which is generally defined as a shareholder that, together with its affiliates and associates, beneficially, directly or indirectly, owns 15 percent or more of our shares entitled to vote at a general meeting.

Item 1B.Unresolved Staff Comments

None.

Item 2.Properties

The description of our property included under “Item 1. Business” is incorporated by reference herein.  We maintain offices, land bases and other facilities worldwide, most of which we lease, including principal executive offices in Steinhausen, Switzerland, and corporate offices in Houston, Texas, and the Cayman Islands.  Our remaining offices and bases are located in various countries in North America, Europe, South America, Asia and Africa.

Item 3.Legal Proceedings

We have certain actions, claims and other matters pending as discussed and reported in “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 13—Commitments and Contingencies” and “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other Matters—Regulatory Matters” in this annual report on Form 10-K.  We are also involved in various tax matters as described in “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 11—Income Taxes” and in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other Matters—Tax matters” in this annual report on Form 10-K.  All such actions, claims, tax and other matters disclosed therein are incorporated herein by reference.

As of December 31, 2021, we were involved in a number of other lawsuits, regulatory matters, disputes and claims, asserted and unasserted, all of which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, to have a material adverse effect on our consolidated financial position, results of operations or cash flows.  We cannot predict with certainty the outcome or effect of any of the matters referred to above or of any such other pending or threatened litigation or legal proceedings.  We can provide no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or claim or dispute will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

On December 17, 2021, Transocean Offshore Deepwater Drilling Inc., our wholly owned subsidiary, received a letter from the U.S. Department of Justice (the “DOJ”) related to alleged violations by our subsidiary of its Clean Water Act (“CWA”) National Pollutant Discharge Elimination System permit (“Permit”).  The alleged violations, involving seven of our drillships, were identified by the U.S. Environmental Protection Agency (“EPA”) following an initial inspection in 2018 of our compliance with the Permit and the CWA and relate to deficiencies with respect to records retention, reporting requirements, discharges, permit limits, inspections and maintenance, and the submission of

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monitoring reports.  In connection with the initial EPA inspection, we initiated modifications to our Permit and CWA compliance processes and maintained a dialogue with the EPA regarding the design and implementation of enhancements to these processes.  At the DOJ’s invitation, in an effort to resolve the matter, we have initiated settlement discussions with the DOJ, and the enforcement action will likely result in our agreeing to take or continue to take certain corrective actions to ensure current and future Permit and CWA compliance and to pay a monetary penalty, which we believe at this time would be immaterial.  We do not believe that the enforcement action would have a material adverse effect on our consolidated financial position, results of operations or cash flow.  If our current expectations relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts.

In addition to the legal proceedings described above, we may from time to time identify other matters that we monitor through our compliance program or in response to events arising generally within our industry and in the markets where we do business.  We evaluate matters on a case by case basis, investigate allegations in accordance with our policies and cooperate with applicable governmental authorities.  Through the process of monitoring and proactive investigation, we strive to ensure no violation of our policies, Code of Integrity or law has occurred, or will occur; however, we can provide no assurance as to the outcome of these matters.

Item 4.Mine Safety Disclosures

Not applicable.

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Information About Our Executive Officers

We have included the following information, presented as of February 14, 2022, on our executive officers for purposes of U.S. securities laws in Part I of this report in reliance on General Instruction G(3) to Form 10-K.  The board of directors elects the officers of the Company, generally on an annual basis.  There is no family relationship between any of our executive officers.

			Age as of
Officer		Office	February 14, 2022
Jeremy D. Thigpen	(a)	Chief Executive Officer	47
Keelan Adamson	(a)	President and Chief Operating Officer	52
Howard E. Davis		Executive Vice President, Chief Administrative Officer and Chief Information Officer	63
Brady K. Long		Executive Vice President and General Counsel	49
Mark L. Mey	(a)	Executive Vice President and Chief Financial Officer	58
David Tonnel		Senior Vice President and Chief Accounting Officer	52

(a) Member of our executive management team for purposes of Swiss law.

Jeremy D. Thigpen is Chief Executive Officer and a member of the Company’s board of directors.  Before joining the Company in this position in April 2015, Mr. Thigpen served as Senior Vice President and Chief Financial Officer at National Oilwell Varco, Inc. from December 2012 to April 2015.  At National Oilwell Varco, Inc., Mr. Thigpen also served as President, Downhole and Pumping Solutions from August 2007 to December 2012, as President of the Downhole Tools Group from May 2003 to August 2007 and as manager of the Downhole Tools Group from April 2002 to May 2003.  From 2000 to 2002, Mr. Thigpen served as the Director of Business Development and Special Assistant to the Chairman for National Oilwell Varco, Inc.  Mr. Thigpen earned a Bachelor of Arts degree in Economics and Managerial Studies from Rice University in 1997, and he completed the Program for Management Development at Harvard Business School in 2001.

Keelan Adamson is President and Chief Operating Officer of the Company.  Before being named to his current position in February 2022, Mr. Adamson served as Executive Vice President and Chief Operations Officer from August 2018 to February 2022, as Senior Vice President, Operations from October 2017 to July 2018 and as Senior Vice President, Operations Integrity and HSE, from June 2015 to October 2017.  Since 2010, Mr. Adamson served in multiple executive positions with responsibilities spanning Engineering and Technical Services, Major Capital Projects, Human Resources, and more recently, Operations Integrity and HSE.  Mr. Adamson started his career as a drilling engineer with BP Exploration in 1991 and joined Transocean in July 1995.  In addition to several management assignments in the U.K., Asia, and Africa, he also held leadership roles in Sales and Marketing, Well Construction and Technology, and as Managing Director for operations in North America, Canada and Trinidad.  Mr. Adamson earned a bachelor's degree in Aeronautical Engineering from The Queens University of Belfast and completed the Advanced Management program at Harvard Business School in 2016.  Mr. Adamson also currently serves on the board of the National Ocean Industries Association.

Howard E. Davis is Executive Vice President, Chief Administrative Officer and Chief Information Officer of the Company.  Before joining the Company in this position in August 2015, Mr. Davis served as Senior Vice President, Chief Administrative Officer and Chief Information Officer of National Oilwell Varco, Inc. from March 2005 to April 2015 and as Vice President, Chief Administrative Officer and Chief Information Officer from August 2002 to March 2005.  Mr. Davis earned a bachelor’s degree from University of Kentucky in 1980, and he completed the Advanced Management Program at Harvard Business School in 2005.

Brady K. Long is Executive Vice President and General Counsel of the Company.  Before being named to his current position in March 2018, Mr. Long served as Senior Vice President and General Counsel from November 2015 to March 2018.  From 2011 to November 2015, when Mr. Long joined the Company, he served as Vice President—General Counsel and Secretary of Ensco plc, which acquired Pride International, Inc. where he had served as Vice President, General Counsel and Secretary since August 2009.  Mr. Long joined Pride International, Inc. in June 2005 as Assistant General Counsel and served as Chief Compliance Officer from June 2006 to February 2009.  He was director of Transocean Partners LLC from May 2016 until December 2016.  Mr. Long previously practiced corporate and securities law with the law firm of Bracewell LLP.  Mr. Long earned a Bachelor of Arts degree from Brigham Young University in 1996, a Juris Doctorate degree from the University of Texas School of Law in 1999 and an Executive LLM in Taxation from New York University in 2019.

Mark L. Mey is Executive Vice President and Chief Financial Officer of the Company.  Before joining the Company in this position in May 2015, Mr. Mey served as Executive Vice President and Chief Financial Officer of Atwood Oceanics, Inc. from January 2015 to May 2015, prior to which he served as Senior Vice President and Chief Financial Officer from August 2010.  Mr. Mey was director of Transocean Partners LLC from June 2015 until December 2016.  He served as Director, Senior Vice President and Chief Financial Officer of Scorpion Offshore Ltd. from August 2005 to July 2010.  Prior to 2005, Mr. Mey held various senior financial and other roles in the drilling and financial services industries, including 12 years with Noble Corporation.  He earned an Advanced Diploma in Accounting and a Bachelor of Commerce degree from the University of Port Elizabeth in South Africa in 1985, and he is a chartered accountant.  Additionally, Mr. Mey completed the Harvard Business School Executive Advanced Management Program in 1998.

David Tonnel is Senior Vice President and Chief Accounting Officer.  Before being named to his current position in April 2017, he served as Senior Vice President, Supply Chain and Corporate Controller from October 2015 to April 2017, as Senior Vice President, Finance and Controller from March 2012 to October 2015 and as Senior Vice President of the Europe and Africa Unit from June 2009 to March 2012.  Mr. Tonnel served as Vice President of Global Supply Chain from November 2008 to June 2009, as Vice President of Integration and Process Improvement from November 2007 to November 2008, and as Vice President and Controller from February 2005 to November 2007.  Prior to February 2005, he served in various financial roles, including Assistant Controller; Finance Manager, Asia Australia Region; and Controller, Nigeria.  Mr. Tonnel joined the Company in 1996 after working for Ernst & Young in France as Senior Auditor.  Mr. Tonnel earned a Master of Science degree in Management from HEC in Paris, France in 1991.

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PART II

Item 5.Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market for Shares of Our Common Equity

Our shares are listed on the New York Stock Exchange under the ticker symbol “RIG.”  On February 14, 2022, we had 656,377,507 shares outstanding and 5,060 holders of record of our shares.

Shareholder Matters

Swiss tax consequences to our shareholders

Overview—The tax consequences discussed below are not a complete analysis or listing of all the possible tax consequences that may be relevant to our shareholders.  Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares and the procedures for claiming a refund of withholding tax.

Swiss income tax on dividends and similar distributions—A non-Swiss holder is not subject to Swiss income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.  However, dividends and similar distributions are subject to Swiss withholding tax, subject to certain exceptions.  See “—Swiss withholding tax on dividends and similar distributions to shareholders.”

Swiss wealth tax—A non-Swiss holder is not subject to Swiss wealth taxes unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.

Swiss capital gains tax upon disposal of shares—A non-Swiss holder is not subject to Swiss income taxes for capital gains unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.  In such case, the non-Swiss holder is required to recognize capital gains or losses on the sale of such shares, which are subject to cantonal, communal and federal income tax.

Swiss withholding tax on dividends and similar distributions to shareholders—A Swiss withholding tax of 35 percent is due on dividends and similar distributions to our shareholders from us, regardless of the place of residency of the shareholder, subject to the exceptions discussed under “—Exemption” below.  We will be required to withhold at such rate and remit on a net basis any payments made to a holder of our shares and pay such withheld amounts to the Swiss federal tax authorities.

Exemption—Distributions to shareholders in the form of a par value reduction or out of qualifying additional paid-in capital for Swiss statutory purposes are exempt from Swiss withholding tax.  On December 31, 2021, the aggregate amount of par value of our outstanding shares was CHF 65.5 million, equivalent to approximately $71.8 million, and the aggregate amount of qualifying additional paid-in capital of our outstanding shares was CHF 13.7 billion, equivalent to approximately $15.0 billion.  Consequently, we expect that a substantial amount of any potential future distributions may be exempt from Swiss withholding tax.

Refund available to Swiss holders—A Swiss tax resident, corporate or individual, can recover the withholding tax in full if such resident is the beneficial owner of our shares at the time the dividend or other distribution becomes due and provided that such resident reports the gross distribution received on such resident’s income tax return, or in the case of an entity, includes the taxable income in such resident’s income statement.

Refund available to non-Swiss holders—If the shareholder that receives a distribution from us is not a Swiss tax resident, does not hold our shares in connection with a permanent establishment or a fixed place of business maintained in Switzerland, and resides in a country that has concluded a treaty for the avoidance of double taxation with Switzerland for which the conditions for the application and protection of and by the treaty are met, then the shareholder may be entitled to a full or partial refund of the withholding tax described above.  Switzerland has entered into bilateral treaties for the avoidance of double taxation with respect to income taxes with numerous countries, including the United States (“U.S.”), whereby under certain circumstances all or part of the withholding tax may be refunded.  The procedures for claiming treaty refunds, and the time frame required for obtaining a refund, may differ from country to country.

Refund available to U.S. residents—The Swiss-U.S. tax treaty provides that U.S. residents eligible for benefits under the treaty can seek a refund of the Swiss withholding tax on dividends for the portion exceeding 15 percent, leading to a refund of 20 percent, or a 100 percent refund in the case of qualified pension funds.  As a general rule, the refund will be granted under the treaty if the U.S. resident can show evidence of the following: (a) beneficial ownership, (b) U.S. residency and (c) meeting the U.S.-Swiss tax treaty’s limitation on benefits requirements.  The claim for refund must be filed with the Swiss federal tax authorities (Eigerstrasse 65, 3003 Bern, Switzerland), not later than December 31 of the third year following the year in which the dividend payments became due.  The relevant Swiss tax form is Form 82C for companies, 82E for other entities and 82I for individuals.  These forms can be obtained from any Swiss Consulate General in the U.S. or from the Swiss federal tax authorities at the above address or can be downloaded from the webpage of the Swiss federal tax administration.  Each form must be completed in triplicate, with each copy duly completed and signed before a notary public in the U.S.  Evidence that the withholding tax was withheld at the source must also be included.

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Stamp duties in relation to the transfer of shares—The purchase or sale of our shares may be subject to Swiss federal stamp taxes on the transfer of securities irrespective of the place of residency of the purchaser or seller if the transaction takes place through or with a Swiss bank or other Swiss securities dealer, as those terms are defined in the Swiss Federal Stamp Tax Act and no exemption applies in the specific case.  If a purchase or sale is not entered into through or with a Swiss bank or other Swiss securities dealer, then no stamp tax will be due.  The applicable stamp tax rate is 0.075 percent for each of the two parties to a transaction and is calculated based on the purchase price or sale proceeds.  If the transaction does not involve cash consideration, the transfer stamp duty is computed on the basis of the market value of the consideration.

Share repurchases

Shares repurchased for the purpose of capital reduction are treated as a partial liquidation subject to a 35 percent Swiss withholding tax based on the difference between the repurchase price and the related amount of par value and the related amount of qualifying additional paid-in capital, if any.  We would be required to remit on a net basis the purchase price with the Swiss withholding tax deducted to a holder of our shares and pay the withholding tax to the Swiss federal tax authorities.  However, for such repurchased shares, the portions of the repurchase price that are attributable to the par value and the qualifying additional paid-in capital for Swiss statutory reporting purposes are not subject to the Swiss withholding tax.

If we repurchase shares, we expect to use an alternative procedure pursuant to which we repurchase our shares via a "virtual second trading line" from market players, such as banks and institutional investors, who are generally entitled to receive a full refund of the Swiss withholding tax.  The use of such “virtual second trading line” with respect to share repurchase programs is subject to approval of the competent Swiss tax and other authorities.  We may not be able to repurchase as many shares as we would like to repurchase for purposes of capital reduction on the “virtual second trading line” without subjecting the selling shareholders to Swiss withholding taxes.  The repurchase of shares for purposes other than for cancellation, such as to retain as treasury shares for use in connection with stock incentive plans, convertible debt or other instruments within certain periods, are not generally subject to Swiss withholding tax.

Under Swiss corporate law, the right of a company and its subsidiaries to repurchase and hold its own shares is limited.  A company may repurchase its shares to the extent it has freely distributable reserves as shown on its Swiss statutory balance sheet in the amount of the purchase price and if the aggregate par value of all shares held by the company as treasury shares does not exceed 10 percent of the company’s share capital recorded in the Swiss Commercial Register, whereby for purposes of determining whether the 10 percent threshold has been reached, shares repurchased under a share repurchase program for cancellation purposes authorized by the company’s shareholders are disregarded.  As of February 14, 2022, Transocean Inc., our wholly owned subsidiary, held as treasury shares 9.86 percent of our issued shares.  Our board of directors could, to the extent freely distributable reserves are available, authorize the repurchase of additional shares for purposes other than cancellation, such as to retain treasury shares for use in satisfying our obligations in connection with incentive plans or other rights to acquire our shares.  Based on the number of shares held as treasury shares as of February 14, 2022, less than one percent of our issued shares could be repurchased for purposes of retention as additional treasury shares.  Although our board of directors has not approved such a share repurchase program for the purpose of retaining repurchased shares as treasury shares, if it did so, any such shares repurchased would be in addition to any shares repurchased under the currently approved program.

Issuer Purchases of Equity Securities

				Total number of shares	Approximate dollar value
	Total number	Average		purchased as part	of shares that may yet
	of shares	price paid		of publicly announced	be purchased under the plans
Period	purchased	per share		plans or programs (a)	or programs (in millions) (a)
October 2021	—	$	—	—	$	3,552
November 2021	—		—	—		3,552
December 2021	—		—	—		3,552
Total	—	$	—	—	$	3,552

(a) In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase for cancellation any amount of our shares for an aggregate purchase price of up to CHF 3.50 billion.  At December 31, 2021, the authorization remaining under the share repurchase program was for the repurchase of our outstanding shares for an aggregate cost of up to CHF 3.24 billion, equivalent to $3.55 billion.  The share repurchase program may be suspended or discontinued by our board of directors or company management, as applicable, at any time.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources and uses of liquidity.”

Item 6.RESERVED

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

The following information should be read in conjunction with the information contained in “Part I. Item 1. Business,” “Part I. Item 1A. Risk Factors” and the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data” elsewhere in this annual report on Form 10-K.  The following discussion of our results of operations and liquidity and capital resources includes comparisons for the years ended December 31, 2021 and 2020.  For a discussion, including comparisons, of our results of operations and liquidity and capital resources for the years ended December 31, 2020 and 2019, see “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 year ended December 31, 2020, filed with the United States (“U.S.”) Securities and Exchange Commission on March 1, 2021.

Business

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells.  As of February 14, 2022, we owned or had partial ownership interests in and operated 37 mobile offshore drilling units, consisting of 27 ultra-deepwater floaters and 10 harsh environment floaters.  As of February 14, 2022, we were constructing two ultra-deepwater drillships.

We provide, as our primary business, contract drilling services in a single operating segment, which involves contracting our mobile offshore drilling rigs, related equipment and work crews to drill oil and gas wells.  We specialize in technically demanding regions of the global offshore drilling business with a particular focus on ultra-deepwater and harsh environment drilling services.  Our drilling fleet is one of the most versatile fleets in the world, consisting of drillships and semisubmersible floaters used in support of offshore drilling activities and offshore support services on a worldwide basis.

We perform contract drilling services by deploying our high-specification fleet in a single, global market that is geographically dispersed in oil and gas exploration and development areas throughout the world.  Although rigs can be moved from one region to another, the cost of moving rigs and the availability of rig-moving vessels may cause the supply and demand balance to fluctuate somewhat between regions.  Still, significant variations between regions do not tend to persist long term because of rig mobility.  The location of our rigs and the allocation of resources to operate, build or upgrade our rigs are determined by the activities and needs of our customers.

Significant Events

Share issuance—In June 2021, we commenced an at the market equity offering program (the “ATM Program”).  In the year ended December 31, 2021, we received aggregate cash proceeds of $158 million, net of issue costs, for the aggregate sale of 36.1 million shares under the ATM Program.  See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Shipyard financing arrangement—In June 2021, Transocean Offshore Deepwater Holdings Limited, a Cayman Islands company and our wholly owned indirect subsidiary, entered into credit agreements with Jurong Shipyard Pte Ltd. establishing facilities (the “Shipyard Loans”) to finance the final payments expected to be owed to the shipyard upon delivery of the ultra-deepwater floaters Deepwater Atlas and Deepwater Titan.  See “—Liquidity and Capital Resources.”

Debt exchanges—In February 2021, we completed private exchanges (the “2021 Private Exchange”) of $323 million aggregate principal amount of outstanding 0.50% exchangeable senior bonds due January 2023 (the “0.50% Exchangeable Senior Bonds”) for $294 million aggregate principal amount of the 4.00% senior guaranteed exchangeable bonds due December 2025 (the “4.00% Senior Guaranteed Exchangeable Bonds”), together with an aggregate cash payment of $11 million.  In the year ended December 31, 2021, we recognized a gain of $51 million associated with the retirement of exchanged debt.  See “—Operating Results” and “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Early debt retirement—In the year ended December 31, 2021, we repurchased in the open market $79 million aggregate principal amount of our debt securities for an aggregate cash payment of $79 million.  In January 2022, we repaid the then-outstanding $18 million aggregate principal amount of the 5.52% Senior Secured Notes due May 2022 (the “5.52% Senior Secured Notes”) early for an aggregate cash payment of $18 million.  See “—Operating Results” and “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Dispositions—During the year ended December 31, 2021, we completed the sale of one harsh environment floater, along with related assets, for which we received $4 million aggregate net cash proceeds and recognized an aggregate net loss of $57 million.  See “—Operating Results.”

Outlook

Drilling market—Our overall outlook for the offshore drilling industry has improved over the past year and remains positive, particularly for high-specification assets, such as those we own and operate.  During the second half of 2021, our customers’ interest in deepwater and harsh environment offshore projects was renewed due to numerous favorable factors, such as sustained higher commodity prices and comparably lower carbon intensity compared to other sources of fossil fuel.  South America, including Guyana, the

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U.S. Gulf of Mexico and, increasingly, West Africa remain key ultra-deepwater market sectors, while Norway continues to represent the largest harsh environment market.

In addition, in 2021, we observed continued strong tendering activity for Asia and Australia.  Licensing activity also indicated an increased interest in these areas as energy companies looked to explore and develop new prospects.  Certain customers began to increase their exploration, production and reserve replacement activities by restarting delayed projects and commencing new campaigns.  We have seen an acceleration in this trend in early 2022.  While we expect this to continue in the near term, and potentially longer, it depends upon many variables, including increased global demand for hydrocarbons, the effects of the COVID-19 pandemic on consumer activity, the actions by some governments and regulators intended to curtail existing and future drilling activities, and other factors.

Offshore drilling activity is increasing in almost every ultra-deepwater market, and due to attrition of the global offshore fleet over the last several years, there are significantly fewer available drilling units and, particularly, an increasing scarcity of the highest specification drilling units as customers look to secure the best equipment for their projects.  In the North Sea harsh environment market, an accelerated level of recovery is anticipated in 2023 through 2026 as the effect of Norway tax incentive programs is realized by our customers.

Global energy demand is expected to increase in member and non-member countries of the Organization for Economic Co-operation and Development.  Non-member countries, in particular, are expected to experience the largest population growth and most significant increases in living standards, creating a compounding effect on energy consumption.  We believe that this forecasted increase in global energy demand will support an increase in demand for oil and gas.  In the context of the sharp decline in production activities that resulted from the pandemic and the lack of investment in exploration and production activities over the past seven years, we believe an increase in demand will precipitate substantial supply constraints that are not easily reversed without significant new investment in drilling.

With deepwater and harsh environment fields offering increasingly competitive returns, combined with their comparably low carbon intensity of production, we expect a significant portion of required spending in fossil fuel development will be allocated to deepwater and harsh environment projects.  As the hydrocarbon supply-demand balance further improves, we expect sustained prices to increase demand for our high-specification fleet of assets and, because there are now fewer offshore drilling rigs than in recent years, further improvement of dayrates.

As of February 14, 2022, our contract backlog was $6.47 billion compared to $7.07 billion as of October 25, 2021.  The risks of drilling project delays, contract renegotiations and contract terminations and cancellations have diminished as oil prices have improved and stabilized.

Fleet status—We refer to the availability of our rigs in terms of the uncommitted fleet rate.  The uncommitted fleet rate is defined as the number of uncommitted days divided by the total number of rig calendar days in the measurement period, expressed as a percentage.  An uncommitted day is defined as a calendar day during which a rig is idle or stacked, is not contracted to a customer and is not committed to a shipyard.  The uncommitted fleet rates exclude the effect of priced options.  As of February 14, 2022, our uncommitted fleet rates for each of the five years in the period ending December 31, 2026 were as follows:

	2022		2023		2024		2025		2026
Uncommitted fleet rate
Ultra-deepwater floaters	60	%	72	%	81	%	83	%	88	%
Harsh environment floaters	48	%	76	%	98	%	100	%	100	%

Performance and Other Key Indicators

Contract backlog—We believe our industry leading contract backlog sets us apart from the competition and provides indicators of our future revenue-earning opportunities.  Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization, contract preparation, other incentive provisions or reimbursement revenues, which are not expected to be significant to our contract drilling revenues.  The contract backlog represents the maximum contract drilling revenues that can be earned considering the contractual operating dayrate in effect during the firm contract period.  The contract backlog for our fleet was as follows:

	February 14,		October 25,		February 12,
	2022		2021		2021
Contract backlog	(In millions)
Ultra-deepwater floaters	$	5,301	$	5,626	$	5,911
Harsh environment floaters		1,165		1,443		1,931
Total contract backlog	$	6,466	$	7,069	$	7,842

Our contract backlog includes only firm commitments, including amounts associated with our contracted newbuild units under construction, which are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution.  It does not include conditional agreements and options to extend firm commitments.

The average contractual dayrate relative to our contract backlog is defined as the average maximum contractual operating dayrate to be earned per operating day in the measurement period.  An operating day is defined as a day for which a rig is contracted to earn a

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dayrate during the firm contract period after operations commence.  At February 14, 2022, the contract backlog and average contractual dayrates for our fleet were as follows:

			For the years ending December 31,
	Total		2022		2023		2024		2025		Thereafter
Contract backlog	(In millions, except average dayrates)
Ultra-deepwater floaters	$	5,301	$	1,255	$	1,149	$	938	$	858	$	1,101
Harsh environment floaters		1,165		753		385		27		—		—
Total contract backlog	$	6,466	$	2,008	$	1,534	$	965	$	858	$	1,101
Average contractual dayrates
Ultra-deepwater floaters	$	406,000	$	320,000	$	390,000	$	469,000	$	470,000	$	467,000
Harsh environment floaters	$	410,000	$	397,000	$	437,000	$	424,000	$	—	$	—
Total fleet average	$	407,000	$	345,000	$	401,000	$	467,000	$	470,000	$	467,000

The actual amount of revenues earned and the actual periods in which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate.  Additional factors that could affect the amount and timing of actual revenues to be recognized include customer liquidity issues and contract terminations that may be available to our customers under certain circumstances.

The contractual operating dayrate may be higher than the actual dayrate we ultimately receive because an alternative contractual dayrate, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances.  The contractual operating dayrate may also be higher than the actual dayrate we ultimately receive because of a number of factors, including rig downtime or suspension of operations.  In certain contracts, the actual dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.  See “Part I. Item 1A. Risk Factors—Risks related to our business—Our current backlog of contract drilling revenues may not be fully realized.”

Average daily revenue—We believe average daily revenue provides a comparative measurement unit for our revenue-earning performance.  Average daily revenue is defined as operating revenues, excluding revenues for contract terminations, reimbursements and contract intangible amortization, earned per operating day.  The average daily revenue for our fleet was as follows:

	Years ended December 31,
	2021		2020		2019
Average daily revenue
Ultra-deepwater floaters	$	355,500	$	324,500	$	337,900
Harsh environment floaters	$	386,200	$	339,600	$	298,500
Midwater floaters	$	—	$	111,400	$	118,400
Total fleet average daily revenue	$	365,600	$	327,500	$	313,400

Our average daily revenue fluctuates relative to market conditions and our revenue efficiency.  The average daily revenue may be affected by incentive performance bonuses or penalties or demobilization fee revenues.  Our total fleet average daily revenue is affected by the mix of rig classes being operated.  Midwater floaters, for example, which we no longer operate, are typically contracted at lower dayrates compared to ultra-deepwater floaters and harsh environment floaters.  Revenues for a contracted newbuild unit are included in the calculation when the rig commences operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale, unless we continue to operate rigs subsequent to sale, in which case we remove the rigs at the time of completion or novation of the contract.

Revenue efficiency—We believe revenue efficiency measures our ability to ultimately convert our contract backlog into revenues.  Revenue efficiency is defined as actual operating revenues, excluding revenues for contract terminations and reimbursements, for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage.  Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding revenues for incentive provisions, reimbursements and contract terminations.  The revenue efficiency rates for our fleet were as follows:

	Years ended December 31,
	2021		2020		2019
Revenue efficiency
Ultra-deepwater floaters	96.1	%	97.2	%	98.5	%
Harsh environment floaters	98.8	%	95.0	%	95.0	%
Midwater floaters	—	%	86.2	%	99.3	%
Total fleet average revenue efficiency	97.0	%	96.3	%	97.2	%

Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate, force majeure rate or zero rate, that may apply under certain circumstances.  Our revenue efficiency rate is

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also affected by incentive performance bonuses or penalties.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We exclude rigs that are not operating under contract, such as those that are stacked.

Rig utilization—We present our rig utilization as an indicator of our ability to secure work for our fleet.  Rig utilization is defined as the total number of operating days divided by the total number of rig calendar days in the measurement period, expressed as a percentage.  The rig utilization rates for our fleet were as follows:

	Years ended December 31,
	2021		2020		2019
Rig utilization
Ultra-deepwater floaters	49.3	%	58.5	%	51.0	%
Harsh environment floaters	64.4	%	72.6	%	77.5	%
Midwater floaters	—	%	37.1	%	36.7	%
Total fleet average rig utilization	53.4	%	62.4	%	57.6	%

Our rig utilization rate declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale.  Accordingly, our rig utilization can increase when we remove idle or stacked units from our fleet.

Operating Results

Year ended December 31, 2021 compared to the year ended December 31, 2020

The following is an analysis of our operating results.  See “—Performance and Other Key Indicators” for definitions of operating days, average daily revenue, revenue efficiency and rig utilization.

	Years ended December 31,
	2021			2020			Change		% Change
	(In millions, except day amounts and percentages)
Operating days		7,236			9,169			(1,933)	(21)	%
Average daily revenue	$	365,600		$	327,500		$	38,100	12	%
Revenue efficiency		97.0	%		96.3	%
Rig utilization		53.4	%		62.4	%
Contract drilling revenues	$	2,556		$	3,152		$	(596)	(19)	%
Operating and maintenance expense		(1,697)			(2,000)			303	15	%
Depreciation and amortization expense		(742)			(781)			39	5	%
General and administrative expense		(167)			(183)			16	9	%
Loss on impairment		—			(597)			597	nm
Loss on disposal of assets, net		(62)			(84)			22	26	%
Operating loss		(112)			(493)			381	77	%
Other income (expense), net
Interest income		15			21			(6)	(29)	%
Interest expense, net of amounts capitalized		(447)			(575)			128	22	%
Gain on restructuring and retirement of debt, net		51			533			(482)	(90)	%
Other, net		23			(27)			50	nm
Loss before income tax expense		(470)			(541)			71	13	%
Income tax expense		(121)			(27)			(94)	nm
Net loss	$	(591)		$	(568)		$	(23)	(4)	%

“nm” means not meaningful.

Contract drilling revenues—Contract drilling revenues decreased for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to the following: (a) approximately $200 million resulting from the settlement of disputes and payments for early termination of a contract in the year ended December 31, 2020 with no comparable activity in the current year period, (b) approximately $185 million resulting from rigs that were idle or in shipyard preparing for contracts in the current year, (c) approximately $155 million resulting from rigs that were stacked in the prior year and (d) approximately $115 million resulting from rigs that were sold.  These decreases were partially offset by the following increases: (a) approximately $55 million resulting from increased average daily revenue and (b) approximately $5 million resulting from higher revenue efficiency.

Costs and expenses—Operating and maintenance costs and expenses decreased for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to the following: (a) approximately $145 million resulting from rigs that were stacked in the prior year, (b) approximately $95 million resulting from rigs that were sold, (c) approximately $55 million resulting from Transocean Norge being idle, (d) approximately $20 million resulting from litigation and settlement costs in the prior year, (d) approximately

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$20 million resulting from severance costs of offshore and onshore personnel, (e) approximately $15 million resulting from onshore personnel costs, excluding severance, (f) approximately $10 million resulting from other changes in rig activity and (g) approximately $10 million resulting from reduced costs related to COVID-19 mitigation.  These decreases were partially offset by the following increases: (a) approximately $28 million resulting from our allowance for excess materials and supplies due to our identification of certain items that were in excess of our expected future usage based on our current market outlook, (b) approximately $35 million resulting from increased personnel costs, primarily due to unfavorable exchange rates, and (c) approximately $20 million resulting from shipyard and maintenance costs primarily driven by out-of-service activities.

Depreciation and amortization expense decreased for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to approximately $22 million resulting from rigs that were sold and approximately $16 million resulting from assets that had reached the end of their useful lives or had been retired.

General and administrative expense decreased for the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to the following: (a) approximately $13 million resulting from reduced personnel costs, including severance, related to our cost savings plan implemented in the year ended December 31, 2020 and (b) approximately $5 million resulting from reduced costs for information systems and technology, partially offset by (c) approximately $6 million resulting from increased strategy and innovation costs.

Loss on impairment or disposal of assets—In the year ended December 31, 2020, we recognized a loss on the impairment of assets, including an aggregate net loss of $556 million associated with assets that we determined were impaired at the time we classified them as held for sale, a loss of $31 million associated with the impairment of our midwater floater asset group and a loss of $10 million associated with the impairment of other assets.

In the year ended December 31, 2021, we recognized an aggregate net loss of $57 million, primarily associated with the sale of a harsh environment floater and related assets.  In the year ended December 31, 2020, we recognized an aggregate net loss of $61 million associated with the sale of one ultra-deepwater floater, three harsh environment floaters and three midwater floaters, along with related assets.  In the years ended December 31, 2021 and 2020, we recognized an aggregate net loss of $5 million and $23 million, respectively, associated with the disposal of assets unrelated to rig sales.

Other income and expense—Interest expense, net of amounts capitalized, decreased in the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to a decrease of $145 million resulting from debt early retired, repaid or restructured, partially offset by an increase of $19 million resulting from debt issued.

In the year ended December 31, 2021, we recognized an aggregate net gain of $51 million associated with the retirement of $323 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds as a result of the 2021 Private Exchange.  In the year ended December 31, 2020, we recognized a net gain on restructuring and retirement of debt, primarily due to the following: (a) an aggregate gain of $427 million associated with the restructuring of debt in the private exchange transactions in August 2020 (the “2020 Private Exchange”) and the exchange offers in September 2020 (the “2020 Exchange Offers”), (b) an aggregate gain of $135 million associated with the retirement of $360 million aggregate principal amount of our debt securities in the tender offers in November 2020, (c) an aggregate gain of $36 million associated with the retirement of $147 million aggregate principal amount of our debt securities repurchased in the open market, partially offset by (d) a loss of $65 million associated with the full redemption of the 9.00% senior notes due July 2023 (the “9.00% Senior Notes”).

Other income, net, increased in the year ended December 31, 2021, compared to the year ended December 31, 2020, primarily due to the following: (a) decreased loss of $22 million resulting from impairment of our equity investment in Orion Holdings (Cayman) Limited (“Orion”), (b) increased income of $24 million resulting from a settlement of litigation and other claims, (c) increased income of $23 million related to the non-service components of net periodic benefit income and (d) decreased losses of $7 million resulting from net changes to currency exchange rates, partially offset by (e) decreased income of $25 million related to our investment in Orion and (f) decreased income of $4 million related to our dual-activity patent.

Income tax expense—In the years ended December 31, 2021 and 2020, our effective tax rate was (25.7) percent and (5.1) percent, respectively, based on loss before income tax expense.  In the years ended December 31, 2021 and 2020, the aggregate effect of discrete period tax items was a net tax expense of $47 million and benefit of $91 million, respectively.  In the year ended December 31, 2021, such discrete items included the effect of tax law changes in Switzerland and jurisdictional ownership changes of certain assets, loss on disposal of assets, expiration and settlements of various uncertain tax positions, gain on retirement of debt, changes to our allowance for excess materials and loss on impairment of an equity investment.  In the year ended December 31, 2020, such discrete items included losses on impairment and disposal of assets, gain on restructuring and retirement of debt, revenues recognized for the settlement of disputes, the loss on impairment of an equity investment, the carryback of net operating losses in the U.S., including the release of valuation allowances previously recorded, settlements and expirations of various uncertain tax positions and accruals for withholding taxes.  In the years ended December 31, 2021 and 2020, our effective tax rate, excluding discrete items, was (18.5) percent and (23.4) percent, respectively, based on loss before income tax expense.  In the year ended December 31, 2021 compared to the year ended December 31, 2020, our effective tax rate increased primarily due changes in the relative blend of income from operations in certain jurisdictions.

Due to our operating activities and organizational structure, our income tax expense does not change proportionally with our income before income taxes.  Significant decreases in our income before income taxes typically lead to higher effective tax rates, while significant

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increases in income before income taxes can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above.  With respect to the effective tax rate calculation for the year ended December 31, 2021, a significant portion of our income tax expense was generated in countries in which income taxes are imposed or treated to be imposed on gross revenues, with the most significant of these countries being Angola and India.  Conversely, the countries in which we incurred the most significant income taxes during this period that were based on income before income tax include the U.S., Switzerland, Norway and Hungary.  Our rig operating structures further complicate our tax calculations, especially in instances where we have more than one operating structure for the taxing jurisdiction and, thus, more than one method of calculating taxes depending on the operating structure utilized by the rig under the contract.

Liquidity and Capital Resources

Sources and uses of cash

At December 31, 2021, we had $976 million in unrestricted cash and cash equivalents and $436 million in restricted cash and cash equivalents.  In the year ended December 31, 2021, our primary sources of cash were net cash provided by operating activities and net cash proceeds from the issuance of shares under the ATM Program.  Our primary uses of cash were debt repayments and capital expenditures.

	Years ended
	December 31,
	2021		2020		Change
	(In millions)
Cash flows from operating activities
Net loss	$	(591)	$	(568)	$	(23)
Non-cash items, net		1,243		1,380		(137)
Changes in operating assets and liabilities, net		(77)		(414)		337
	$	575	$	398	$	177

Net cash provided by operating activities increased primarily due to (a) reduced cash paid for interest, (b) the cash payment of $125 million released from restricted cash to satisfy our remaining obligations under the Plaintiff Steering Committee settlement agreement in June 2020 with no comparable activity in the current year and (c) reduced cash paid for income taxes.

	Years ended
	December 31,
	2021		2020		Change
	(In millions)
Cash flows from investing activities
Capital expenditures	$	(208)	$	(265)	$	57
Investment in loans to unconsolidated affiliates		(33)		(2)		(31)
Investments in unconsolidated affiliates		(1)		(19)		18
Proceeds from disposal of assets, net		9		24		(15)
Proceeds from maturities of unrestricted and restricted investments		—		5		(5)
	$	(233)	$	(257)	$	24

Net cash used in investing activities decreased primarily due to (a) reduced capital expenditures unrelated to our two newbuilds under construction and (b) reduced investments in unconsolidated affiliates, partially offset by (c) increased investments in loans to our unconsolidated affiliates and (d) reduced proceeds from disposal of assets.

	Years ended
	December 31,
	2021		2020		Change
	(In millions)
Cash flows from financing activities
Repayments of debt	$	(606)	$	(1,637)	$	1,031
Proceeds from issuance of shares, net of issue costs		158		—		158
Proceeds from issuance of debt, net of discounts and issue costs		—		743		(743)
Other, net		(42)		(36)		(6)
	$	(490)	$	(930)	$	440

Net cash used in financing activities decreased primarily due to (a) reduced cash used to repay debt, primarily as a result of the full redemption of $714 million aggregate principal amount of the 9.00% Senior Notes in February 2020 and (b) aggregate net cash proceeds from the issuance of 36.1 million shares under the ATM Program in the current year, partially offset by (c) net cash proceeds from the issuance of the 8.00% senior notes due February 2027 (the “8.00% Senior Notes”) in January 2020.

Sources and uses of liquidity

Overview—We expect to use existing unrestricted cash balances, internally generated cash flows, borrowings under the Shipyard Loans or the Secured Credit Facility, as defined below, or proceeds from the disposal of assets, the issuance of additional debt or the issuance of additional shares under the ATM Program to fulfill anticipated obligations, which may include capital expenditures, working capital

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and other operational requirements, scheduled debt maturities or other payments.  We may consider establishing additional financing arrangements with banks or other capital providers, and subject to market conditions and other factors, we may be required to provide collateral for any such future financing arrangements.  We continue to evaluate additional potential liability management transactions in connection with our ongoing efforts to prudently manage our capital structure and improve our liquidity.  In each case subject to then existing market conditions and our expected liquidity needs, among other factors, we may continue to use existing unrestricted cash balances, internally generated cash flows and proceeds from asset sales to pursue liability management transactions, including among others, purchasing or exchanging one or more existing series of our debt securities in the open market, in privately negotiated transactions, through tender offers or through exchange offers.  Any future purchases, exchanges or other transactions may be on the same terms or on terms that are more or less favorable to holders than the terms of any prior transaction, including the exchange transactions completed in the years ended December 31, 2021 and 2020.  We can provide no assurance as to which, if any, of these alternatives, or combinations thereof, we may choose to pursue in the future, if at all, or as to the timing with respect to any future transactions.

The ongoing effect of the COVID-19 pandemic, including virus variants, and the volatility in oil prices could have significant adverse consequences for general economic, financial and business conditions, as well as for our business and financial position and the business and financial position of our customers and suppliers and may, among other things, impact our ability to generate cash flows from operations, access the capital markets on acceptable terms or at all, and affect our future need or ability to borrow under our Secured Credit Facility.  In addition to our potential sources of funding, the effects of such global events may impact our liquidity or need to alter our allocation or sources of capital, implement further cost reduction measures and change our financial strategy.

We have generated positive cash flows from operating activities over recent years and, although we cannot provide assurances, we currently expect that such cash flows will continue to be positive over the next year.  However, among other factors, if the drilling market deteriorates, or if we experience poor operating results, or if we incur expenses to, for example, reactivate, stack or otherwise assure the marketability of our fleet, cash flows from operations may be reduced or negative.

Our ability and willingness to access the debt and equity markets is a function of a variety of events, including, among others, general economic conditions, industry conditions, market conditions and market perceptions of us and our industry and credit rating agencies’ views of our debt.  The rating of the majority of our long-term debt (“Debt Rating”) is below investment grade.  The Debt Rating is causing us to experience increased fees and interest rates under our Secured Credit Facility and agreements governing certain of our senior notes.  Future downgrades may further restrict our ability to access the debt market for sources of capital and may negatively impact the cost of such capital at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions.  An economic downturn like the one we are currently experiencing could have an impact on the lenders participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us.

Secured Credit Facility—As of December 31, 2021, we have a $1.33 billion secured revolving credit facility established under a bank credit agreement (as amended from time to time, the “Secured Credit Facility”), which is scheduled to expire on June 22, 2023.  The Secured Credit Facility is guaranteed by Transocean Ltd. and certain wholly owned subsidiaries.  The Secured Credit Facility is secured by, among other things, a lien on nine of our ultra-deepwater floaters and two of our harsh environment floaters.  The maximum borrowing capacity will be reduced to $1.00 billion if, and so long as, our leverage ratio, measured as the aggregate principal amount of debt outstanding to earnings before interest, taxes, depreciation and amortization, exceeds 10.00 to 1.00.  The Secured Credit Facility contains covenants that, among other things, include maintenance of a minimum guarantee coverage ratio of 3.0 to 1.0, a minimum collateral coverage ratio of 2.1 to 1.0, a maximum debt to capitalization ratio of 0.60 to 1.00 and minimum liquidity of $500 million.  The Secured Credit Facility also restricts the ability of Transocean Ltd. and certain of our subsidiaries to, among other things, merge, consolidate or otherwise make changes to the corporate structure, incur liens, incur additional indebtedness, enter into transactions with affiliates and pay dividends and other distributions.  In order to borrow under the Secured Credit Facility, we must, at the time of the borrowing request, not be in default under the Secured Credit Facility and make certain representations and warranties, including with respect to compliance with laws and solvency, to the lenders.  Repayment of borrowings under the Secured Credit Facility are subject to acceleration upon the occurrence of an event of default.  Under the agreements governing certain of our debt and finance lease, we are also subject to various covenants, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions.  A default under our public debt indentures, the agreements governing our senior secured notes, our finance lease contract or any other debt owed to unaffiliated entities that exceeds $125 million could trigger a default under the Secured Credit Facility and, if not waived by the lenders, could cause us to lose access to the Secured Credit Facility.  At February 14, 2022, we had no borrowings outstanding, $16 million of letters of credit issued, and we had $1.32 billion of available borrowing capacity under the Secured Credit Facility.

Shipyard financing arrangement—In June 2021, we and Jurong Shipyard Pte Ltd. entered into the Shipyard Loans to finance all or a portion of the final payments expected to be owed to the shipyard upon delivery of the ultra-deepwater floaters Deepwater Atlas and Deepwater Titan.  We expect to borrow approximately $370 million upon delivery of Deepwater Atlas in the six months ending June 30, 2022, and we expect to borrow approximately $90 million upon delivery of Deepwater Titan in the six months ending December 31, 2022.  The Shipyard Loans are guaranteed by Transocean Inc.  Borrowings under the Shipyard Loan for Deepwater Atlas will be secured by, among other security, a lien on the rig.  In certain circumstances, the maximum aggregate borrowing capacity under the Shipyard Loan for Deepwater Titan may be increased to approximately $440 million, and such Shipyard Loan may also be secured by, among other security, a lien on the rig.  We will repay the borrowings, together with interest of 4.5 percent per annum, according to the selected installment schedule over a maximum of a six-year period following delivery of the drilling rigs.  We have the right to prepay any outstanding borrowings, in full or

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in part, without penalty.  The Shipyard Loans contain covenants that, among other things, limits the ability of the subsidiary owners of the drilling rigs to incur certain types of additional indebtedness or make certain additional commitments or investments.  At February 14, 2022, we had no borrowings outstanding under the Shipyard Loans.

Share issuance—On June 14, 2021, we entered into an equity distribution agreement with a sales agent for the offer and sale of our shares, with up to an aggregate net offering price of $400 million, pursuant to the ATM Program.  We intend to use the net proceeds from the sale of our shares under the ATM Program for general corporate purposes, which may include, among other things the repayment or refinancing of indebtedness and the funding of working capital, capital expenditures, investments and additional balance sheet liquidity.  In the year ended December 31, 2021, we received aggregate cash proceeds of $158 million, net of issue costs, for the aggregate sale of 36.1 million shares under the ATM Program.

Debt exchanges—On February 26, 2021, we issued $294 million aggregate principal amount of the 4.00% Senior Guaranteed Exchangeable Bonds and made an aggregate cash payment of $11 million in the 2021 Private Exchange for $323 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds.  The 4.00% Senior Guaranteed Exchangeable Bonds are guaranteed by Transocean Ltd. and the same subsidiaries of Transocean Inc. that guarantee the 2.50% senior guaranteed exchangeable bonds due January 2027 (the “2.50% Senior Guaranteed Exchangeable Bonds”) and the 11.50% senior guaranteed notes due January 2027 (the “11.50% Senior Guaranteed Notes”).  The indenture that governs the 4.00% Senior Guaranteed Exchangeable Bonds also requires such bonds to be repurchased upon the occurrence of certain fundamental changes and events, at specified prices depending on the particular fundamental change or event, which include changes and events related to certain (i) change of control events applicable to Transocean Ltd. or Transocean Inc., (ii) the failure of our shares to be listed or quoted on a national securities exchange and (iii) specified tax matters.  The 4.00% Senior Guaranteed Exchangeable Bonds may be exchanged at any time prior to the close of business on the second business day immediately preceding the maturity date at a current exchange rate of 190.4762 Transocean Ltd. shares per $1,000 note, which implies an exchange price of $5.25 per share, subject to adjustment upon the occurrence of certain events, and any such exchange may be settled in cash, Transocean Ltd. shares or a combination of cash and Transocean Ltd. shares, at our election.

On August 14, 2020, we issued $238 million aggregate principal amount of the 2.50% Senior Guaranteed Exchangeable Bonds in the 2020 Private Exchange for $397 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds.  The 2.50% Senior Guaranteed Exchangeable Bonds are fully and unconditionally guaranteed by Transocean Ltd. and certain wholly owned indirect subsidiaries of Transocean Inc.  We may redeem all or a portion of the 2.50% Senior Guaranteed Exchangeable Bonds (i) on or after August 14, 2022, if certain conditions related to the price of our shares have been satisfied, at a price equal to 100 percent of the aggregate principal amount and (ii) on or after August 14, 2023, at specified redemption prices.  The indenture that governs the 2.50% Senior Guaranteed Exchangeable Bonds contains covenants that, among other things, limit our ability to incur certain liens on our drilling units without equally and ratably securing the notes, engage in certain sale and lease back transactions covering any of our drilling units, allow our subsidiaries to incur certain additional debt, and consolidate, merge or enter into a scheme of arrangement qualifying as an amalgamation.  The indenture that governs the 2.50% Senior Guaranteed Exchangeable Bonds also requires such bonds to be repurchased upon the occurrence of certain fundamental changes and events, at specified prices depending on the particular fundamental change or event, which include changes and events related to certain (i) change of control events applicable to Transocean Ltd. or Transocean Inc., (ii) the failure of our shares to be listed or quoted on a national securities exchange and (iii) specified tax matters.  The 2.50% Senior Guaranteed Exchangeable Bonds may be exchanged at any time prior to the close of business on the second business day immediately preceding the maturity date or the redemption date at a current exchange rate of 162.1626 Transocean Ltd. shares per $1,000 note, which implies an exchange price of $6.17 per share, subject to adjustment upon the occurrence of certain events.

On September 11, 2020, we issued $687 million aggregate principal amount of the 11.50% Senior Guaranteed Notes in the 2020 Exchange Offers, pursuant to an exchange offer memorandum, dated August 10, 2020, as supplemented, for an aggregate principal amount of $1.5 billion of several series of our existing debt securities that were validly tendered and accepted for purchase.  The 11.50% Senior Guaranteed Notes are fully and unconditionally guaranteed by Transocean Ltd. and certain wholly owned indirect subsidiaries of Transocean Inc.  We may redeem all or a portion of the 11.50% Senior Guaranteed Notes prior to July 30, 2023 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.  We may also use the net cash proceeds of certain equity offerings by Transocean Ltd. to redeem, on one or more occasions prior to July 30, 2023, up to a maximum of 40 percent of the original aggregate principal amount of the 11.50% Senior Guaranteed Notes, subject to certain adjustments, at a redemption price equal to 111.50 percent of the aggregate principal amount.  The indenture that governs the 11.50% Senior Guaranteed Notes contains covenants that, among other things, limit our ability to incur certain liens on our drilling units without equally and ratably securing the notes, engage in certain sale and lease back transactions covering any of our drilling units, allow our subsidiaries to incur certain additional debt, make certain internal transfers of our drilling units and consolidate, merge or enter into a scheme of arrangement qualifying as an amalgamation.

Early debt retirement—In January 2022, we made an aggregate cash payment of $18 million to repay the then-outstanding $18 million aggregate principal amount of the 5.52% Senior Secured Notes, and as a result, the noteholders subsequently released all liens, the mortgage on the secured rig and $106 million from restricted cash accounts.  In the years ended December 31, 2021 and 2020, we made an aggregate cash payment of $79 million and $110 million, respectively, to repurchase in the open market $79 million and $147 million, respectively, aggregate principal amount of our debt securities.  In February 2020, we made an aggregate cash payment of $767 million, including the make-whole premium, to redeem in full the then-outstanding 9.00% Senior Notes.  In November 2020, we completed the cash

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tender offers to purchase certain debt securities, and as a result, we made an aggregate cash payment of $222 million to settle the validly tendered notes.

Debt issuances—On January 17, 2020, we issued $750 million aggregate principal amount of our 8.00% Senior Notes, and we received aggregate cash proceeds of $743 million, net of issue costs.  We may redeem all or a portion of the 8.00% Senior Notes on or prior to February 1, 2023 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.

Equity and debt investments—We hold equity and debt investments in Orion, the company that, through its wholly owned subsidiary, owns the harsh environment floater Transocean Norge.  In June 2021, we agreed to participate in a financing arrangement for Orion, at a rate of 33.0 percent, equivalent to our ownership interest in Orion and made a cash investment of $33 million in the loan facility.

We also hold equity and debt investments in certain unconsolidated affiliates that are involved in researching and developing technology to improve efficiency, reliability, sustainability and safety in drilling and other activities.  One of these companies, Nauticus Robotics, develops highly sophisticated, ultra-sustainable marine robots and intelligent software to power them, and commercializes our patented HaloGuard℠ system, which alarms, notifies and, if required, halts equipment to avoid injury to personnel who move into danger zones.  Nauticus Robotics has recently entered into a definitive business combination agreement with a publicly traded special purpose acquisition company that will result in it becoming a publicly listed company.

Litigation settlement—In June 2020, the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”) released the then-remaining $125 million of assets held in the escrow account established to satisfy our remaining obligations under the settlement agreement that we and the Plaintiff Steering Committee filed in May 2015 with the MDL Court, in which most claims against us for damages related to the blowout of the Macondo well in April 2010 were consolidated by the U.S. Judicial Panel on Multidistrict Litigation.  Following the release of assets, all significant litigation, including civil and criminal claims, resulting from the Macondo well incident had been resolved.

Share repurchase program—In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to CHF 3.50 billion.  On February 12, 2010, our board of directors authorized our management to implement the share repurchase program.  At December 31, 2021, the authorization remaining under the share repurchase program was for the repurchase of up to CHF 3.24 billion, equivalent to approximately $3.55 billion, of our outstanding shares.  We intend to fund any repurchases using available cash balances and cash from operating activities.  The share repurchase program could be suspended or discontinued by our board of directors or company management, as applicable, at any time.  We may decide, based on our ongoing capital requirements, the price of our shares, regulatory and tax considerations, cash flow generation, the amount and duration of our contract backlog, general market conditions, debt rating considerations and other factors, that we should retain cash, reduce debt, make capital investments or acquisitions or otherwise use cash for general corporate purposes.  Decisions regarding the amount, if any, and timing of any share repurchases will be made from time to time based on these factors.  Any repurchased shares under the share repurchase program would be held by us for cancellation by the shareholders at a future general meeting of shareholders.  See “Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities—Shareholder Matters.”

Contractual obligations—At December 31, 2021, our contractual obligations stated at face value, were as follows:

			Years ending December 31,
	Total		2022		2023 - 2024		2025 - 2026		Thereafter
	(in millions)
Debt	$	7,243	$	524	$	1,661	$	1,799	$	3,259
Interest on debt		2,385		389		666		455		875
Finance lease liability		541		71		141		141		188
Operating lease liabilities		178		14		26		25		113
Purchase obligations		1,002		950		52		—		—
Service agreement obligations		800		116		247		264		173
Total	$	12,149	$	2,064	$	2,793	$	2,684	$	4,608

As of December 31, 2021, our defined benefit pension and other postemployment plans represented an aggregate liability of $132 million, representing the aggregate projected benefit obligation, net of the aggregate fair value of plan assets.  The carrying amount of this liability is influenced by, among others, significant current and future assumptions, funding contributions, returns on plan assets, participant demographics, and plan amendments.  We excluded this amount from our contractual obligations presented above due to the uncertainties resulting from these factors and because the amount is not representative of future liquidity requirements.  See Notes to Consolidated Financial Statements—Note 10—Postemployment Benefit Plans.

As of December 31, 2021, we have unrecognized tax benefits of $435 million, including interest and penalties, against which we have recorded net operating loss deferred tax assets of $320 million, resulting in net unrecognized tax benefits of $115 million, including interest and penalties, that upon reversal would favorably impact our effective tax rate.  Although a portion of these could settle or reverse in the coming year, we have excluded this amount from our contractual obligations presented above due to the high degree of uncertainty regarding the timing of future cash outflows associated with these liabilities and the period in which any cash settlement may be made with the respective taxing authorities.  See Notes to Consolidated Financial Statements—Note 11—Income Taxes.

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Other commercial commitments—We have other commercial commitments, such as standby letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, customs, tax and other obligations in various jurisdictions.  The cash obligations of these commitments, which are primarily geographically concentrated in Brazil, are not normally called because we typically comply with the underlying performance requirements.  Standby letters of credit are issued under various committed and uncommitted credit lines, some of which require cash collateral.  At December 31, 2021, the aggregate cash collateral held by banks for letters of credit and surety bonds was $8 million.

At December 31, 2021, these obligations stated in U.S. dollar equivalents and their time to expiration were as follows:

			Years ending December 31,
	Total		2022		2023 - 2024		2025 - 2026		Thereafter
	(in millions)
Standby letters of credit	$	18	$	11	$	7	$	—	$	—
Surety bonds		146		1		73		61		11
Total	$	164	$	12	$	80	$	61	$	11

We have established a wholly owned captive insurance company to insure various risks of our operating subsidiaries.  Access to the cash and cash equivalents of the captive insurance company may be limited due to local regulatory restrictions.  At December 31, 2021, the captive insurance company held cash and cash equivalents of $52 million, and such balance is expected to range from $25 million to $75 million through December 31, 2022.  The balance of the cash and cash equivalents held by the captive insurance company varies, depending on (i) premiums received and (ii) the timing and magnitude of claims and dividends paid by the captive insurance company.

Drilling fleet

Expansion—From time to time, we review possible acquisitions of businesses and drilling rigs, as well as noncontrolling interests in other companies, and we may make significant future capital commitments for such purposes.  We may also consider investments related to major rig upgrades, new rig construction, or the acquisition of a rig under construction.  Any such acquisition or investment could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.  Our failure to subsequently secure drilling contracts in these instances, if not already secured, could have an adverse effect on our results of operations or cash flows.

In the years ended December 31, 2021 and 2020, we made capital expenditures of $208 million and $265 million, respectively, including $174 million and $143 million, respectively, for our newbuild construction projects.  The historical and projected capital expenditures and non-cash capital additions for our ongoing newbuild construction projects were as follows:

	Total costs
	through
	December 31,		Years ending December 31,
	2021		2022		2023		Total
	(In millions)
Deepwater Atlas (a)	$	443	$	610	$	37	$	1,090
Deepwater Titan (b)		512		599		59		1,170
Total	$	955	$	1,209	$	96	$	2,260

(a) Deepwater Atlas, an ultra-deepwater drillship under construction at the Jurong Shipyard Pte Ltd. in Singapore.  We currently expect that the shipyard will be ready to deliver Deepwater Atlas in the first half of 2022, and upon delivery, we expect to borrow approximately $370 million under the Shipyard Loan, which may be discounted for imputed interest, to finance the final installment to the shipyard (see “—Sources and uses of liquidity”).  The rig is expected to commence operations under its drilling contract, in the first of two phases, in the second half of 2022, using a 15,000 pounds per square inch blowout preventer.  Before the start of the second phase, the rig will undergo installation of a 20,000 pounds per square inch blowout preventer and related equipment, which is expected to be commissioned in the year ending December 31, 2023.

(b) Deepwater Titan, an ultra-deepwater drillship under construction at the Jurong Shipyard Pte Ltd. in Singapore.  We currently expect that the shipyard will be ready to deliver Deepwater Titan in the second half of 2022, and upon delivery, we expect to borrow approximately $90 million under the Shipyard Loan, which may be discounted for imputed interest, to finance a portion of the final installment to the shipyard (see “—Sources and uses of liquidity”).  The rig is expected to commence operations under its drilling contract in the first half of 2023.  The projected capital additions include estimates for an upgrade for two 20,000 pounds per square inch blowout preventers and other equipment required by our customer.

The ultimate amount of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity, the costs associated with the current regulatory environment and customer requested capital improvements and equipment for which the customer agrees to reimburse us.  As with any major shipyard project that takes place over an extended period of time, the actual costs, the timing of expenditures and the project completion date may vary from estimates based on numerous factors, including actual contract terms, weather, exchange rates, shipyard labor conditions, availability of suppliers to recertify equipment and the market demand for components and resources required for drilling unit construction.  We intend to fund the cash requirements relating to our capital expenditures not financed under the Shipyard Loans by using available cash balances, cash generated from operations and asset sales, borrowings under our Secured Credit Facility and financing arrangements with banks or other capital providers.  Economic conditions and other factors could impact the availability of these sources of funding.  See “—Sources and uses of liquidity.”

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Dispositions—From time to time, we may also review the possible disposition of certain drilling assets.  Considering market conditions, we have committed to plans to sell certain lower specification drilling units for scrap value.  During the two-year period ended December 31, 2021, we identified eight such drilling units that we sold for scrap value or other purposes.  During the year ended December 31, 2021, we completed the sale of one harsh environment floater and related assets, and we received net cash proceeds of $4 million.  During the year ended December 31, 2020, we completed the sale of one ultra-deepwater floater, three harsh environment floaters and three midwater floaters, along with related assets, and we received aggregate net cash proceeds of $20 million.  We continue to evaluate the drilling units in our fleet and may identify additional lower-specification drilling units to be sold for scrap value.

Related Party Transactions

We engage in certain related party transactions with our unconsolidated affiliates, the most significant of which are under agreements with Orion.  We have a management services agreement for the operation, stacking and maintenance of the harsh environment floater Transocean Norge and a marketing services agreement for the marketing of the rig.  We also leased the rig under a short-term bareboat charter agreement, which expired in June 2021.  Prior to the rig’s placement into service, we engaged in certain related party transactions with Orion under a shipyard care agreement for the construction of the rig and other matters related to its completion and delivery.  Additionally, in June 2021, Orion refinanced its shipyard loans under a financing arrangement for $100 million, in which we participated at a rate equivalent to our ownership interest in Orion.  Borrowings under the financing arrangement are secured by Transocean Norge.  See Notes to Consolidated Financial Statements—Note 4—Unconsolidated Affiliates.

In August 2020, Perestroika AS, an entity affiliated with one of our directors that beneficially owns approximately 10 percent of our shares, exchanged $356 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds for $213 million aggregate principal amount of 2.50% Senior Guaranteed Exchangeable Bonds.  Perestroika AS has certain registration rights related to its shares and shares that may be issued in connection with any exchange of its 2.50% Senior Guaranteed Exchangeable Bonds.  See Notes to Consolidated Financial Statements—Note 9—Debt.

Critical Accounting Policies and Estimates

Overview—We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the U.S., which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities.  These estimates require significant judgments and assumptions.  On an ongoing basis, we evaluate our estimates, including those related to our income taxes, property and equipment, equity investments, contingencies, assets held for sale, intangibles, allowance for excess materials and supplies, allowance for credit losses, postemployment benefit plans, leases and share-based compensation.  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 these estimates.

We consider the following to be our critical accounting policies and estimates since they are very important to the portrayal of our financial condition and results and require our most subjective and complex judgments.  We have discussed the development, selection and disclosure of such policies and estimates with the audit committee of our board of directors.  For a discussion of our significant accounting policies and accounting standards updates, refer to our Notes to Consolidated Financial Statements—Note 2—Significant Accounting Policies and Note 3—Accounting Standards Update.

Income taxes—We provide for income taxes based on expected taxable income, statutory rates, tax laws and tax planning opportunities available to us in the jurisdictions in which we operate or have a taxable presence.  The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures.  Consequently, our income tax expense does not change proportionally with our income or loss before income taxes.

Uncertain tax positions—We apply significant judgment to evaluate our tax positions based on the interpretation of tax laws in various jurisdictions and with the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of income, deductions and tax credits.  Our tax liability in any given year could be affected by changes in tax laws, regulations, agreements, and treaties, currency exchange restrictions or our level or profitability of operations in each jurisdiction.  The tax laws relating to the offshore drilling industry in certain jurisdictions in which we operate are not well developed, requiring us to apply incremental judgment.  Although we employ the best information available at the time we prepare our annual tax provision, a number of years may elapse before the tax liabilities in the various jurisdictions are ultimately determined.

We are undergoing examinations of our tax returns in a number of taxing jurisdictions for various years.  We review our liabilities on an ongoing basis and, to the extent audits or other events cause us to adjust the liabilities accrued in prior periods, we recognize those adjustments in the period of the event.  Our tax liabilities are dependent on numerous factors that cannot be reasonably projected, including among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the taxes

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paid to one country that either produce, or fail to produce, offsetting tax changes in other countries.  Consequently, we cannot reasonably estimate the future impact of changes to the assumptions and estimates related to our annual tax provision.

Unrecognized tax benefits—We establish liabilities for estimated tax exposures, and the provisions and benefits resulting from changes to those liabilities are included in our annual tax provision along with related interest and penalties.  Such tax exposures include potential challenges to permanent establishment positions, intercompany pricing, disposition transactions, and withholding tax rates and their applicability.  These exposures may be affected by changes in applicable tax law or other factors, which could cause us to revise our prior estimates, and are generally resolved through the settlement of audits within these tax jurisdictions or by judicial means.  At December 31, 2021 and 2020, our unrecognized tax benefits were approximately $435 million and $419 million, respectively.

Valuation allowance—We apply significant judgment to determine whether our deferred tax assets will be fully or partially realized.  Our evaluation requires us to consider all available positive and negative evidence, including projected future taxable income and the existence of cumulative losses in recent years.  We continually evaluate strategies that could allow for the future utilization of our deferred tax assets.  When it is estimated to be more likely than not that all or some portion of certain deferred tax assets, such as foreign tax credit carryovers or net operating loss carryforwards, will not be realized, we establish a valuation allowance for the amount of the deferred tax assets that is considered to be unrealizable.  During the years ended December 31, 2021 and 2020, in connection with our evaluation of the projected realizability of our deferred tax assets, we determined that our consolidated cumulative loss incurred over the recent three-year period has limited our ability to consider other subjective evidence, such as projected contract activity rather than contract backlog.  See Notes to Consolidated Financial Statements—Note 11—Income Taxes.

Property and equipment—We apply significant judgment to account for our property and equipment, consisting primarily of offshore drilling rigs and related equipment, related to estimates and assumptions for cost capitalization, useful lives and salvage values.  At December 31, 2021 and 2020, the carrying amount of our property and equipment was $17.10 billion and $17.67 billion, respectively, representing 83 percent and 81 percent, respectively, of our total assets.

Capitalized costs—We capitalize costs incurred to enhance, improve and extend the useful lives of our property and equipment and expense costs incurred to repair and maintain the existing condition of our rigs.  For newbuild construction projects, we also capitalize the initial preparation, mobilization and commissioning costs incurred until the drilling unit is placed into service.  Capitalized costs increase the carrying amounts of, and depreciation expense for, the related assets, which also impact our results of operations.

Useful lives and salvage values—We depreciate our assets using the straight-line method over their estimated useful lives after allowing for salvage values.  We estimate useful lives and salvage values by applying judgments and assumptions that reflect both historical experience and expectations regarding future operations, rig utilization and asset performance.  Useful lives and salvage values of rigs are difficult to estimate due to a variety of factors, including (a) technological advances that impact the methods or cost of oil and gas exploration and development, (b) changes in market or economic conditions and (c) changes in laws or regulations affecting the drilling industry.  Applying different judgments and assumptions in establishing the useful lives and salvage values would likely result in materially different net carrying amounts and depreciation expense for our assets.  We reevaluate the remaining useful lives and salvage values of our rigs when certain events occur that directly impact the useful lives and salvage values of the rigs, including changes in operating condition, functional capability and market and economic factors.  We may also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on future marketability.  At December 31, 2021, a hypothetical one-year increase in the useful lives of all of our rigs would cause a decrease in our annual depreciation expense of approximately $31 million and a hypothetical one-year decrease would cause an increase in our annual depreciation expense of approximately $36 million.

Long-lived asset impairment—We review our property and equipment for impairment when events or changes in circumstances indicate that the carrying amounts of our assets held and used may not be recoverable.  Potential impairment indicators include rapid declines in commodity prices and related market conditions, declines in dayrates or utilization, cancellations of contracts or credit concerns of multiple customers.  During periods of oversupply, we may idle or stack rigs for extended periods of time or we may elect to sell certain rigs for scrap, which could be an indication that an asset group may be impaired since supply and demand are the key drivers of rig utilization and our ability to contract our rigs at economical rates.  Our rigs are mobile units, equipped to operate in geographic regions throughout the world and, consequently, we may mobilize rigs from an oversupplied region to a more lucrative and undersupplied region when it is economical to do so.  Many of our contracts generally allow our customers to relocate our rigs from one geographic region to another, subject to certain conditions, and our customers utilize this capability to meet their worldwide drilling requirements.  Accordingly, our rigs are considered to be interchangeable within classes or asset groups, and we evaluate impairment by asset group.  We consider our asset groups to be ultra-deepwater floaters and harsh environment floaters.

We assess recoverability of assets held and used by projecting undiscounted cash flows for the asset group being evaluated.  When the carrying amount of the asset group is determined to be unrecoverable, we recognize an impairment loss, measured as the amount by which the carrying amount of the asset group exceeds its estimated fair value.  To estimate the fair value of each asset group, we apply a variety of valuation methods, incorporating income, market and cost approaches.  We may weigh the approaches, under certain circumstances, when relevant data is limited, when results are inconclusive or when results deviate significantly.  Our estimate of fair value generally requires us to use significant unobservable inputs, representative of Level 3 fair value measurements, including assumptions related to the long-term future performance of our asset groups, such as projected revenues and costs, dayrates, rig utilization and revenue efficiency.  These projections involve uncertainties that rely on assumptions about demand for our services, future market conditions and

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technological developments.  Because our business is cyclical in nature, the results of our impairment testing are expected to vary significantly depending on the timing of the assessment relative to the business cycle.  Altering either the timing of or the assumptions used to estimate fair value and significant unanticipated changes to the assumptions could materially alter an outcome that could otherwise result in an impairment loss.  Given the nature of these evaluations and their application to specific asset groups and specific time periods, it is not possible to reasonably quantify the impact of changes in these assumptions.  In the year ended December 31, 2020, we recognized a loss of $31 million, which had no tax effect, associated with the impairment of the midwater floater asset group.  See Notes to Consolidated Financial Statements—Note 7—Long-Lived Assets.

Equity-method investments and impairment—We review our equity-method investments for potential impairment when events or changes in circumstances indicate that the carrying amount of the investment might not be recoverable in the near term.  Such circumstances include the following: (a) evidence we are unable to recover the carrying amount of our investment, (b) evidence that the investee is unable to sustain earnings that would justify the carrying amount or (c) the current fair value of the investment is less than the carrying amount.  If an evaluation of such circumstances results in the determination that an impairment that is other than temporary exists, we recognize an impairment loss, measured as the amount by which the carrying amount of the investment exceeds its estimated fair value.  To estimate the fair value of the investment, we apply valuation methods that rely primarily on the income and market approaches.  Our estimate of fair value generally requires us to use significant unobservable inputs, representative of Level 3 fair value measurements, including assumptions related to the estimated discount rate and the investee’s long-term future operational performance factors, such as projected revenues and costs and market factors, including demand for the investee’s industry, services and product lines.  Such projections involve significant uncertainties and require significant judgment.  In the years ended December 31, 2021 and 2020, we recognized a loss of $37 million and $59 million, respectively, associated with an other-than-temporary impairment of the carrying amount of our equity-method investments.  See Notes to Consolidated Financial Statements—Note 4—Unconsolidated Affiliates.

Other Matters

Regulatory matters

We occasionally receive inquiries from governmental regulatory agencies regarding our operations around the world, including inquiries with respect to various tax, environmental, regulatory and compliance matters.  To the extent appropriate under the circumstances, we investigate such matters, respond to such inquiries and cooperate with the regulatory agencies.  See Notes to Consolidated Financial Statements—Note 13—Commitments and Contingencies.

Tax matters

We conduct operations through our various subsidiaries in countries throughout the world.  Each country has its own tax regimes with varying nominal rates, deductions and tax attributes that are subject to changes resulting from new legislation, interpretation or guidance.  From time to time, as a result of these changes, we may revise previously evaluated tax positions, which could cause us to adjust our recorded tax assets and liabilities.  Tax authorities in certain jurisdictions are examining our tax returns and, in some cases, have issued assessments.  We intend to defend our tax positions vigorously.  Although we can provide no assurance as to the outcome of the aforementioned changes, examinations or assessments, we do not expect the ultimate liability to have a material adverse effect on our consolidated financial position or results of operations; however, it could have a material adverse effect on our consolidated cash flows.  See Notes to Consolidated Financial Statements—Note 11—Income Taxes.

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Interest rate risk—We are exposed to interest rate risk, primarily associated with our long-term debt, including current maturities.  The following table presents the scheduled installment amounts and related weighted-average interest rates of our long-term debt instruments by contractual maturity date.  The scheduled installment amounts include the contractual principal and interest payments resulting from previously restructured debt.  The following table presents information as of December 31, 2021 for each of the five years in the period ending December 31, 2026 and thereafter (in millions, except interest rate percentages):

	Years ending December 31,
	2022			2023			2024			2025			2026			Thereafter			Total		Fair value
Debt
Fixed rate (USD)	$	524		$	798		$	863		$	1,069		$	730		$	3,259		$	7,243	$	5,661
Average interest rate		5.49	%		4.58	%		6.01	%		5.65	%		6.71	%		5.47	%

At December 31, 2021 and 2020, the fair value of our outstanding debt was $5.66 billion and $4.82 billion, respectively.  During the year ended December 31, 2021, the fair value of our debt increased by $841 million due to the following: (a) a net increase of $1.24 billion resulting from changes in the market prices of our outstanding debt, (b) a net increase of $117 million due to the issuance of the 4.00% senior guaranteed exchangeable bonds due December 2025 in private exchanges for the 0.50% exchangeable senior bonds due January 2023, partially offset by (c) a decrease of $474 million due to repayments of debt at scheduled maturities and (d) a decrease of $43 million due to debt repurchased in the open market.  See Notes to Consolidated Financial Statements—Note 9—Debt.

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The majority of our cash equivalents is subject to variable interest rates or short-term interest rates and such cash equivalents would earn commensurately higher rates of return if interest rates increase.

Currency exchange rate risk—We are exposed to currency exchange rate risk primarily related to employee compensation costs and purchasing costs that are denominated in currencies other than our functional currency, the U.S. dollar.  We use a variety of techniques to minimize the exposure to currency exchange rate risk, including the structuring of customer contract payment terms and occasional use of forward exchange contracts.  Our primary tool to manage currency exchange rate risk involves structuring customer contracts to provide for payment in both U.S. dollars and local currency.  The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term.  Due to various factors, including customer acceptance, local banking laws, national content requirements, other statutory requirements, local currency convertibility, local inflation and revenue efficiency, actual local currency needs may vary from those realized in the customer contracts, resulting in partial exposure to currency exchange rate risk.  The currency exchange effect resulting from our international operations generally has not had a material impact on our operating results.  See Notes to Consolidated Financial Statements—Note 19—Risk Concentration.

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Item 8.Financial Statements and Supplementary Data

Management’s Report on Internal Control Over Financial Reporting

Management of Transocean Ltd. (the “Company,” “we” or “our”) is responsible for the integrity and objectivity of the financial information included in this annual report.  We have prepared our financial statements in accordance with accounting principles generally accepted in the United States, which require us to apply our best judgement to make estimates and assumptions for certain amounts.  We are responsible for establishing and maintaining a system of internal controls and procedures to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements.  Our internal control system is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection of qualified personnel, and a written Code of Integrity.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.  Also, projections of any evaluation of effectiveness in 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.

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934.  Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission, as described in Internal Control-Integrated Framework, as published in 2013.  Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2021.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the audit committee of the Company’s board of directors, subject to ratification by our shareholders.  Ernst & Young LLP has audited and reported on the consolidated financial statements of Transocean Ltd. and subsidiaries, and the Company’s internal control over financial reporting.  The reports of the independent auditors are contained in this annual report.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Transocean Ltd.

Opinion on Internal Control over Financial Reporting

We have audited Transocean Ltd. and subsidiaries’ internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).  In our opinion, Transocean Ltd. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, and the related consolidated statements of operations, comprehensive loss, equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a), and our report dated February 23, 2022, expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.  We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit 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/ Ernst & Young LLP

Houston, Texas
February 23, 2022

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Transocean Ltd.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Transocean Ltd. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive loss, equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the consolidated financial statements).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2022, expressed an unqualified opinion thereon.

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 Matters

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

Income Taxes

Description of the Matter

As discussed in Notes 2 and 11 to the consolidated financial statements, the Company operates in multiple jurisdictions through a complex operating structure and is subject to applicable tax laws, treaties or regulations in each jurisdiction where it operates.  The Company’s provision for income taxes is based on the tax laws and rates applicable in each jurisdiction.  The Company recognizes tax benefits they believe are more likely than not to be sustained upon examination by the taxing authorities based on the technical merits of the position. Auditing management’s provision for income taxes and related deferred taxes was complex because of the Company’s multi-national operating structure.  In addition, a higher degree of auditor judgment was required to evaluate the Company’s deferred tax provision as a result of the Company’s interpretation of tax law in each jurisdiction across its multiple subsidiaries.

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How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s income tax provision process, including controls over management’s review of the identification and valuation of deferred income taxes and changes in tax laws and regulations that may impact the Company’s deferred income tax provision. Our audit procedures also included, among others, (i) obtaining an understanding of the Company’s overall tax structure, evaluating changes in the Company’s tax structure that occurred during the year as well as changes in tax law, and assessing the interpretation of those changes under the relevant jurisdiction’s tax law; (ii) utilizing tax resources with appropriate knowledge of local jurisdictional laws and regulations; (iii) evaluating the completeness and accuracy of deferred income taxes, and (iv) assessing the reasonableness of the Company’s valuation allowance on deferred tax assets, including projections of taxable income from the future reversal of existing taxable temporary differences.
	Equity-Method Investment in Orion Holdings (Cayman) Limited
Description of the Matter	As discussed in Notes 2 and 4, the Company recorded an impairment loss of $37 million associated with its equity-method investment in Orion Holdings (Cayman) Limited (Orion) upon determination that the carrying amount of its investment exceeded the estimated fair value and that the impairment was other than temporary.   At December 31, 2021, the aggregate carrying amount of the Company’s equity-method investment in Orion was $57 million. Auditing management’s equity-method investment valuation was complex and judgmental due to the estimation required in determining the fair value of the investment.  In particular, the fair value estimate of the equity-method investment in Orion was sensitive to significant assumptions such as the discount rate, future demand and supply of harsh environment floaters, rig utilization, revenue efficiency and dayrates.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process to determine the fair value of the investment in Orion, including controls over management’s review of the significant assumptions described above as well as over the underlying data used in the fair value determination. To test the estimated fair value of the Company’s equity-method investment in Orion, we performed audit procedures that included, among others, assessing the valuation methodologies utilized by management and testing the significant assumptions discussed above and the completeness and accuracy of the underlying data used by the Company in its analysis.  We involved a valuation specialist to assist in our evaluation of the Company's model, valuation methodology and significant assumptions.  We reviewed for contrary evidence related to the determination of the fair value of the equity-method investment, including reviewing relevant market data and internal Company forecasts.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 1999.

Houston, Texas
February 23, 2022

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

	Years ended December 31,
	2021		2020		2019
Contract drilling revenues	$	2,556	$	3,152	$	3,088
Costs and expenses
Operating and maintenance		1,697		2,000		2,140
Depreciation and amortization		742		781		855
General and administrative		167		183		193
		2,606		2,964		3,188
Loss on impairment		—		(597)		(609)
Loss on disposal of assets, net		(62)		(84)		(12)
Operating loss		(112)		(493)		(721)
Other income (expense), net
Interest income		15		21		43
Interest expense, net of amounts capitalized		(447)		(575)		(660)
Gain (loss) on restructuring and retirement of debt		51		533		(41)
Other, net		23		(27)		181
		(358)		(48)		(477)
Loss before income tax expense		(470)		(541)		(1,198)
Income tax expense		121		27		59
Net loss		(591)		(568)		(1,257)
Net income (loss) attributable to noncontrolling interest		1		(1)		(2)
Net loss attributable to controlling interest	$	(592)	$	(567)	$	(1,255)
Loss per share, basic and diluted	$	(0.93)	$	(0.92)	$	(2.05)
Weighted-average shares, basic and diluted		637		615		612

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In millions)

	Years ended December 31,
	2021		2020		2019
Net loss	$	(591)	$	(568)	$	(1,257)
Net income (loss) attributable to noncontrolling interest		1		(1)		(2)
Net loss attributable to controlling interest		(592)		(567)		(1,255)
Components of net periodic benefit income (costs) before reclassifications		175		38		(25)
Components of net periodic benefit costs reclassified to net loss		10		25		4
Other comprehensive income (loss) before income taxes		185		63		(21)
Income taxes related to other comprehensive income (loss)		(6)		(2)		—
Other comprehensive income (loss)		179		61		(21)
Other comprehensive income attributable to noncontrolling interest		—		—		—
Other comprehensive income (loss) attributable to controlling interest		179		61		(21)
Total comprehensive loss		(412)		(507)		(1,278)
Total comprehensive income (loss) attributable to noncontrolling interest		1		(1)		(2)
Total comprehensive loss attributable to controlling interest	$	(413)	$	(506)	$	(1,276)

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

	December 31,
	2021		2020
Assets
Cash and cash equivalents	$	976	$	1,154
Accounts receivable, net		492		583
Materials and supplies, net		392		434
Restricted cash and cash equivalents		436		406
Other current assets		148		163
Total current assets		2,444		2,740
Property and equipment		23,152		23,040
Less accumulated depreciation		(6,054)		(5,373)
Property and equipment, net		17,098		17,667
Contract intangible assets		173		393
Deferred tax assets, net		7		9
Other assets		959		995
Total assets	$	20,681	$	21,804
Liabilities and equity
Accounts payable	$	228	$	194
Accrued income taxes		17		28
Debt due within one year		513		505
Other current liabilities		545		659
Total current liabilities		1,303		1,386
Long-term debt		6,657		7,302
Deferred tax liabilities, net		447		315
Other long-term liabilities		1,068		1,366
Total long-term liabilities		8,172		8,983
Commitments and contingencies
Shares, CHF 0.10 par value, 891,379,306 authorized, 142,363,356 conditionally authorized, 728,176,456 issued
and 655,505,335 outstanding at December 31, 2021, and 824,650,660 authorized, 142,363,647 conditionally
authorized, 639,676,165 issued and 615,140,276 outstanding at December 31, 2020		64		60
Additional paid-in capital		13,683		13,501
Accumulated deficit		(2,458)		(1,866)
Accumulated other comprehensive loss		(84)		(263)
Total controlling interest shareholders’ equity		11,205		11,432
Noncontrolling interest		1		3
Total equity		11,206		11,435
Total liabilities and equity	$	20,681	$	21,804

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

	Years ended December 31,			Years ended December 31,
	2021	2020	2019	2021		2020		2019
	Quantity			Amount
Shares
Balance, beginning of period	615	612	610	$	60	$	59	$	59
Issuance of shares	40	3	2		4		1		—
Balance, end of period	655	615	612	$	64	$	60	$	59
Additional paid-in capital
Balance, beginning of period				$	13,501	$	13,424	$	13,394
Share-based compensation					28		31		37
Issuance of shares					154		(1)		—
Equity component of convertible debt instruments					—		46		—
Reallocated capital for transactions with holders of noncontrolling interest					—		1		—
Other, net					—		—		(7)
Balance, end of period				$	13,683	$	13,501	$	13,424
Accumulated deficit
Balance, beginning of period				$	(1,866)	$	(1,297)	$	(67)
Net loss attributable to controlling interest					(592)		(567)		(1,255)
Effect of adopting accounting standards updates					—		(2)		25
Balance, end of period				$	(2,458)	$	(1,866)	$	(1,297)
Accumulated other comprehensive loss
Balance, beginning of period				$	(263)	$	(324)	$	(279)
Other comprehensive income (loss) attributable to controlling interest					179		61		(21)
Effect of adopting accounting standards update					—		—		(24)
Balance, end of period				$	(84)	$	(263)	$	(324)
Total controlling interest shareholders’ equity
Balance, beginning of period				$	11,432	$	11,862	$	13,107
Total comprehensive loss attributable to controlling interest					(413)		(506)		(1,276)
Share-based compensation					28		31		37
Issuance of shares					158		—		—
Equity component of convertible debt instruments					—		46		—
Reallocated capital for transactions with holders of noncontrolling interest					—		1		—
Other, net					—		(2)		(6)
Balance, end of period				$	11,205	$	11,432	$	11,862
Noncontrolling interest
Balance, beginning of period				$	3	$	5	$	7
Total comprehensive income (loss) attributable to noncontrolling interest					1		(1)		(2)
Acquisition of noncontrolling interest					(3)		—		—
Reallocated capital for transactions with holders of noncontrolling interest					—		(1)		—
Balance, end of period				$	1	$	3	$	5
Total equity
Balance, beginning of period				$	11,435	$	11,867	$	13,114
Total comprehensive loss					(412)		(507)		(1,278)
Share-based compensation					28		31		37
Issuance of shares					158		—		—
Equity component of convertible debt instrument					—		46		—
Other, net					(3)		(2)		(6)
Balance, end of period				$	11,206	$	11,435	$	11,867

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years ended December 31,
	2021		2020		2019
Cash flows from operating activities
Net loss	$	(591)	$	(568)	$	(1,257)
Adjustments to reconcile to net cash provided by operating activities:
Contract intangible asset amortization		220		215		187
Depreciation and amortization		742		781		855
Share-based compensation expense		28		31		37
Loss on impairment		—		597		609
Loss on impairment of investment in unconsolidated affiliates		37		62		—
Loss on disposal of assets, net		62		84		12
(Gain) loss on restructuring and retirement of debt		(51)		(533)		41
Gain on termination of construction contracts		—		—		(132)
Deferred income tax expense		128		60		248
Other, net		77		83		41
Changes in deferred revenues, net		(108)		(73)		43
Changes in deferred costs, net		(6)		12		(33)
Changes in other operating assets and liabilities, net		37		(353)		(311)
Net cash provided by operating activities		575		398		340
Cash flows from investing activities
Capital expenditures		(208)		(265)		(387)
Investment in loans to unconsolidated affiliate		(33)		(2)		—
Investments in unconsolidated affiliates		(1)		(19)		(77)
Proceeds from disposal of assets, net		9		24		70
Proceeds from maturities of unrestricted and restricted investments		—		5		123
Other, net		—		—		3
Net cash used in investing activities		(233)		(257)		(268)
Cash flows from financing activities
Repayments of debt		(606)		(1,637)		(1,325)
Proceeds from issuance of shares, net of issue costs		158		—		—
Proceeds from issuance of debt, net of discounts and issue costs		—		743		1,056
Other, net		(42)		(36)		(43)
Net cash used in financing activities		(490)		(930)		(312)
Net decrease in unrestricted and restricted cash and cash equivalents		(148)		(789)		(240)
Unrestricted and restricted cash and cash equivalents, beginning of period		1,560		2,349		2,589
Unrestricted and restricted cash and cash equivalents, end of period	$	1,412	$	1,560	$	2,349

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells.  As of December 31, 2021, we owned or had partial ownership interests in and operated a fleet of 37 mobile offshore drilling units, consisting of 27 ultra-deepwater floaters and 10 harsh environment floaters.  As of December 31, 2021, we were constructing two ultra-deepwater drillships.

We provide, as our primary business, contract drilling services in a single operating segment, which involves contracting our mobile offshore drilling rigs, related equipment and work crews to drill oil and gas wells.  We specialize in technically demanding regions of the global offshore drilling business with a particular focus on ultra-deepwater and harsh environment drilling services.  Our drilling fleet is one of the most versatile fleets in the world, consisting of drillships and semisubmersible floaters used in support of offshore drilling activities and offshore support services on a worldwide basis.

We perform contract drilling services by deploying our high-specification fleet in a single, global market that is geographically dispersed in oil and gas exploration and development areas throughout the world.  The location of our rigs and the allocation of our resources to build or upgrade rigs are determined by the activities and needs of our customers.

Note 2—Significant Accounting Policies

Accounting estimates—To prepare financial statements in accordance with accounting principles generally accepted in the United States (“U.S.”), we must make judgments by applying estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities.  On an ongoing basis, we evaluate our estimates and assumptions, including those related to our income taxes, property and equipment, equity investments, contingencies, allowance for excess materials and supplies, intangibles, allowance for credit losses, leases, postemployment benefit plans and share-based compensation.  We base our estimates and assumptions on historical experience and other factors that we believe are reasonable.  Actual results could differ from such estimates.

Fair value measurements—We estimate fair value at an exchange price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants.  Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data (“Level 3”).  When a valuation requires multiple input levels, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Consolidation—We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes.  We eliminate intercompany transactions and accounts in consolidation.  We apply the equity method of accounting for an equity investment in an unconsolidated entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary.  We measure other equity investments at fair value if the investment has a fair value that is readily determinable; otherwise, we measure the investment at cost, less any impairment.  We separately present within equity on our consolidated balance sheets the ownership interests attributable to parties with noncontrolling interests in our consolidated subsidiaries, and we separately present net income attributable to such parties on our consolidated statements of operations.  See Note 4—Unconsolidated Affiliates and Note 14—Equity.

Revenues and related pre-operating costs—We recognize revenues earned under our drilling contracts based on variable dayrates, which range from a full operating dayrate to lower rates or zero rates for periods when drilling operations are interrupted or restricted, based on the specific activities we perform during the contract on an hourly, or more frequent, basis.  Such dayrate consideration is attributed to the distinct time period to which it relates within the contract term, and therefore, is recognized as we perform the services.  When the operating dayrate declines over the contract term, we recognize revenues on a straight-line basis over the estimated contract period.  We recognize reimbursement revenues and the corresponding costs as we provide the customer-requested goods and services, when such reimbursable costs are incurred while performing drilling operations.  Prior to performing drilling operations, we may receive pre-operating revenues, on either a fixed lump-sum or variable dayrate basis, for mobilization, contract preparation, customer-requested goods and services or capital upgrades, for which we record a contract liability and recognize as revenues on a straight-line basis over the estimated contract period.  We recognize losses for loss contracts as such losses are incurred.  We recognize revenues for demobilization over the contract period unless otherwise constrained.  We recognize revenues from contract terminations as we fulfill our obligations and all contingencies have been resolved.  We apply the optional exemption that permits us to exclude disclosure of the estimated transaction price related to the variable portion of unsatisfied performance obligations at the end of the reporting period, as our transaction price is based

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

on a single performance obligation consisting of a series of distinct hourly, or more frequent, periods, the variability of which will be resolved at the time of the future services.

To obtain contracts with our customers, we incur pre-operating costs to prepare a rig for contract and mobilize a rig to the drilling location.  We defer such pre-operating contract preparation and mobilization costs for recognition in operating and maintenance costs over the estimated contract period on a straight-line basis, consistent with the general pace of activity.  See Note 5—Revenues.

Contract intangible assets—We recognize contract intangible assets related to acquired executory contracts, such as drilling contracts.  The drilling contract intangible assets represent the amount by which the fixed dayrates of the acquired contracts were above the market dayrates that were available or expected to be available during the term of the contract for similar contracts, measured as of the acquisition date.  We amortize the carrying amount of the drilling contract intangible assets using the straight-line method as a reduction of contract drilling revenues over the expected remaining contract period.  See Note 6—Contract Intangible Assets.

Share-based compensation—To measure the fair values of granted or modified service-based restricted share units, we use the market price of our shares on the grant date or modification date.  To measure the fair values of granted or modified stock options, we use the Black-Scholes-Merton option-pricing model and apply assumptions for the expected life, risk-free interest rate, expected volatility and dividend yield.  To measure the fair values of granted or modified performance-based restricted share units subject to market factors, we use a Monte Carlo simulation model and, in addition to the assumptions applied for the Black-Scholes-Merton option-pricing model, we use a risk neutral approach and an average price at the performance start date.  To measure the fair values of granted or modified performance-based restricted share units that are subject to performance targets, we use the market price of our shares on the grant date or modification date adjusted for the projected performance rate expected to be achieved at the end of the measurement period.  We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees or non-employee directors.  We recognize such compensation expense on a straight-line basis over the service period through the date the employee or non-employee director is no longer required to provide service to earn the award.  See Note 15—Share-Based Compensation.

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects and only capitalize interest costs during periods in which progress for the construction projects continues to be underway.  In the years ended December 31, 2021, 2020 and 2019, we capitalized interest costs of $50 million, $47 million and $38 million, respectively, for our construction work in progress.

Functional currency—We consider the U.S. dollar to be the functional currency for all of our operations since the majority of our revenues and expenditures are denominated in U.S. dollars, which limits our exposure to currency exchange rate fluctuations.  We recognize currency exchange rate gains and losses in other, net.  In the years ended December 31, 2021, 2020 and 2019, we recognized a net loss of $1 million, a net loss of $8 million and a net gain of $2 million, respectively, related to currency exchange rates.

Income taxes—We provide for income taxes based on expected taxable income, statutory rates, tax laws and tax planning opportunities available to us in the jurisdictions in which we operate or have a taxable presence.  We recognize the effect of changes in tax laws as of the date of enactment.  We recognize potential global intangible low-taxed income inclusions as a period cost.

We maintain liabilities for estimated tax exposures in our jurisdictions of operation, and we recognize the provisions and benefits resulting from changes to those liabilities in our income tax expense or benefit along with related interest and penalties.  Income tax exposure items include potential challenges to permanent establishment positions, intercompany pricing, disposition transactions, and withholding tax rates and their applicability.  These tax exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means, but can also be affected by changes in applicable tax law or other factors, which could cause us to revise past estimates.

We measure deferred tax assets and liabilities using enacted tax rates that will apply in the years in which the deferred tax assets and liabilities are expected to be recovered or paid.  In evaluating our ability to realize deferred tax assets, we consider all available positive and negative evidence, including projected future taxable income and the existence of cumulative losses in recent years.  We record a valuation allowance for deferred tax assets when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.  For example, we may record a valuation allowance for deferred tax assets resulting from net operating losses incurred during the year in certain jurisdictions for which the benefit of the losses will not be realized or for foreign tax credit carryforwards that may expire prior to their utilization.  See Note 11—Income Taxes.

Cash and cash equivalents—We consider cash equivalents to include highly liquid debt instruments with original maturities of three months or less, such as time deposits with commercial banks that have high credit ratings, U.S. Treasury and government securities, Eurodollar time deposits, certificates of deposit and commercial paper.  We may also invest excess funds in no-load, open-ended, management investment trusts.  Such management trusts invest exclusively in high-quality money market instruments.

Restricted cash and cash equivalents—We maintain restricted cash and cash equivalents that are either pledged for debt service under certain bond indentures, as required under certain bank credit arrangements, or held in accounts that are subject to restrictions due to legislation, regulation or court order.  We classify such restricted cash and cash equivalents in current assets if the restriction is expected to expire or otherwise be resolved within one year or if such funds are considered to offset liabilities that are properly classified as current liabilities. See Note 9—Debt and Note 13—Commitments and Contingencies.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Materials and supplies—We record materials and supplies at their average cost less an allowance for excess items.  We estimate the allowance for excess items based on historical experience and expectations for future use of the materials and supplies.  During the year ended December 31, 2021, we identified certain materials and supplies that were in excess of our expected future usage based on our current market outlook.  As a result of these items, we increased our allowance by $28 million ($0.04 per diluted share, net of tax).  At December 31, 2021 and 2020, our allowance for excess items was $183 million and $143 million, respectively.

Assets held for sale—We classify an asset as held for sale when the facts and circumstances meet the criteria for such classification, including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or termination.  At December 31, 2021 and 2020, we had no assets classified as held for sale.

Property and equipment—We apply judgment to account for our property and equipment, consisting primarily of offshore drilling rigs and related equipment, related to estimates and assumptions for cost capitalization, useful lives and salvage values.  We base our estimates and assumptions on historical experience and expectations regarding future industry conditions and operations.  At December 31, 2021, the aggregate carrying amount of our property and equipment represented approximately 83 percent of our total assets.

We capitalize expenditures for newbuilds, renewals, replacements and improvements, including capitalized interest, if applicable, and we recognize the expense for maintenance and repair costs as incurred.  For newbuild construction projects, we also capitalize the initial preparation, mobilization and commissioning costs incurred until the drilling unit is placed into service.  Upon sale or other disposition of an asset, we recognize a net gain or loss on disposal of the asset, which is measured as the difference between the net carrying amount of the asset and the net proceeds received.  We compute depreciation using the straight-line method after allowing for salvage values.

The estimated original useful life of our drilling units is 35 years, our buildings and improvements range from two to 30 years and our machinery and equipment range from four to 20 years.  We reevaluate the remaining useful lives and salvage values of our rigs when certain events occur that directly impact the useful lives and salvage values of the rigs, including changes in operating condition, functional capability and market and economic factors.  When evaluating the remaining useful lives of rigs, we also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on future marketability.

Long-lived asset impairment—We review the carrying amounts of long-lived assets, including property and equipment and right-of-use assets, for potential impairment when events occur or circumstances change that indicate that the carrying amount of such assets may not be recoverable.  For assets classified as held and used, we determine recoverability by evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilization of the asset group under review.  We consider our asset groups to be ultra-deepwater floaters and harsh environment floaters.  When an impairment of one or more of our asset groups is indicated, we measure the impairment as the amount by which the asset group’s carrying amount exceeds its estimated fair value.  We measure the fair values of our asset groups by applying a variety of valuation methods, incorporating a combination of cost, income and market approaches, using projected discounted cash flows and estimates of the exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market participants as of the measurement date.  For an asset classified as held for sale, we consider the asset to be impaired to the extent its carrying amount exceeds its estimated fair value less cost to sell.  See Note 7—Long-Lived Assets.

Equity investments and impairment—We review our equity-method investments, and other equity investments for which a readily determinable fair value is not available, for potential impairment when events or changes in circumstances indicate that the carrying amount of the investment might not be recoverable in the near term.  If we determine that an impairment that is other than temporary exists, we recognize an impairment loss, measured as the amount by which the carrying amount of the investment exceeds its estimated fair value.  To estimate the fair value of the investment, we apply valuation methods that rely primarily on the income and market approaches.  In the years ended December 31, 2021 and 2020, we recognized a loss of $37 million and $62 million, respectively, associated with the other-than-temporary impairment of the carrying amount of our equity investments. See Note 4—Unconsolidated Affiliates.

Pension and other postemployment benefit plans—We use a measurement date of January 1 for determining net periodic benefit costs and December 31 for determining plan benefit obligations and the fair values of plan assets.  We determine our net periodic benefit costs based on a market-related value of assets that reduces year-to-year volatility by including investment gains or losses subject to amortization over a five-year period from the year in which they occur.  We calculate investment gains or losses for this purpose as the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  If gains or losses exceed 10 percent of the greater of plan assets or plan liabilities, we amortize such gains or losses over the average expected future service period of the employee participants.

We measure our actuarially determined obligations and related costs for our defined benefit pension and other postemployment benefit plans, retiree life insurance and medical benefits, by applying assumptions, the most significant of which include long-term rate of return on plan assets, discount rates and mortality rates.  For the long-term rate of return, we develop our assumptions regarding the expected rate of return on plan assets based on historical experience and projected long-term investment returns, and we weight the assumptions based on each plan’s asset allocation.  For the discount rate, we base our assumptions on a yield curve approach using Aa-rated corporate

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

bonds and the expected timing of future benefit payments.  At December 31, 2021 and 2020, our pension and other postemployment benefit plan obligations represented an aggregate liability of $132 million and $277 million, respectively, and an aggregate asset of $102 million and $37 million, respectively, representing the funded status of the plans.  See Note 10—Postemployment Benefit Plans.

Contingencies—We perform assessments of our contingencies on an ongoing basis to evaluate the appropriateness of our liabilities and disclosures for such contingencies.  We establish liabilities for estimated loss contingencies when we believe a loss is probable and the amount of the probable loss can be reasonably estimated.  Once established, we adjust the carrying amount of a contingent liability upon the occurrence of a recognizable event when facts and circumstances change, altering our previous assumptions with respect to the likelihood or amount of loss.  We recognize corresponding assets for those loss contingencies that we believe are probable of being recovered through insurance.  We recognize expense for legal costs as they are incurred, and we recognize a corresponding asset for such legal costs only if we expect such legal costs to be recovered through insurance.

Note 3—Accounting Standards Update

Recently adopted accounting standards

Debt with conversion and other options—Effective January 1, 2021, we early adopted the accounting standards update that simplifies the accounting for convertible instruments, such as our exchangeable debt, by limiting the accounting models that result in separately recognizing embedded conversion features from the host contract.  The accounting standards update also enhances information transparency by making targeted improvements to the disclosures for convertible instruments and earnings per share guidance.  Our adoption did not result in any accounting changes for the 0.50% exchangeable senior bonds due January 2023 (the “0.50% Exchangeable Senior Bonds”) or the 2.50% senior guaranteed exchangeable bonds due January 2027 (the “2.50% Senior Guaranteed Exchangeable Bonds”).  Under previous accounting guidance, for the 4.00% senior guaranteed exchangeable bonds due December 2025 (the “4.00% Senior Guaranteed Exchangeable Bonds”), we would have recorded the debt and exchange features separately and, consequently, we would have recognized in current and future periods greater amortization, as a component of interest expense.  See Note 9—Debt.

Note 4—Unconsolidated Affiliates

Equity investments—We hold noncontrolling equity investments in various unconsolidated companies, including (a) our 33.0 percent ownership interest in Orion Holdings (Cayman) Limited (together with its subsidiary, “Orion”), a Cayman Islands company that, through its wholly owned subsidiary, owns the harsh environment floater Transocean Norge, and (b) our interests in certain companies that are involved in researching and developing technology to improve efficiency, reliability, sustainability and safety for drilling and other activities.  At December 31, 2021 and 2020, the aggregate carrying amount of our equity investments was $91 million and $138 million, respectively, recorded in other assets.

Our equity-method investment in Orion is the most significant of our equity investments.  In the years ended December 31, 2020 and 2019, we made an aggregate cash contribution of $8 million and $74 million, respectively, to Orion.  In the years ended December 31, 2021 and 2020, we recognized a loss of $37 million and $59 million, respectively, which had no tax effect, recorded in other, net, associated with the impairment of our equity investment in Orion upon determination that the carrying amount exceeded the estimated fair value and that the impairment was other than temporary.  We estimated the fair value of our investment by applying the income method using significant unobservable inputs, representative of Level 3 fair value measurements, including an assumed discount rate of 12 percent and assumptions about the future performance of the investment, such as future demand and supply for harsh environment floaters, rig utilization, revenue efficiency and dayrates.  At December 31, 2021 and 2020, the aggregate carrying amount of our equity investment in Orion was $57 million and $104 million, respectively.

Related party transactions—We engage in certain related party transactions with our unconsolidated affiliates, the most significant of which are under agreements with Orion.  We have a management services agreement for the operation and maintenance of the harsh environment floater Transocean Norge and a marketing services agreement for the marketing of the rig.  We also leased the rig under a short-term bareboat charter agreement, which expired in June 2021.  Prior to the rig’s placement into service, we also engaged in certain related party transactions with Orion under a shipyard care agreement for the construction of the rig and other matters related to its completion and delivery.  Additionally, we procure services and equipment from other unconsolidated affiliates for technological innovation.

In the years ended December 31, 2021, 2020 and 2019, we received an aggregate cash payment of $16 million, $46 million and $96 million, respectively, under the shipyard care agreement with Orion, primarily related to the commissioning, preparation and mobilization of Transocean Norge.  In the years ended December 31, 2021, 2020 and 2019, we recognized rent expense of $12 million, $22 million and $9 million, respectively, recorded in operating and maintenance costs, and made an aggregate cash payment of $15 million, $22 million and $6 million, respectively, to charter the rig and rent other equipment from Orion.  In the years ended December 31, 2021, 2020 and 2019, we made an aggregate cash payment of $6 million, $15 million and $11 million, respectively, to other unconsolidated affiliates for research and development and for equipment to reduce emissions and improve reliability.

Additionally, in June 2021, Orion refinanced its shipyard loans under a financing arrangement for $100 million, in which we participated at a rate equivalent to our ownership interest in Orion.  Borrowings under the financing arrangement are secured by

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Transocean Norge.  The financing arrangement, which expires in June 2024, requires interest to be paid on outstanding borrowings at the London Interbank Offered Rate plus a margin of 6.50 percent per annum.  In the year ended December 31, 2021, we made a cash investment in loans of $33 million.  At December 31, 2021, the outstanding borrowings, including accrued and unpaid interest, due to us under the financing arrangement were $34 million, recorded in other assets.

Note 5—Revenues

Overview—We earn revenues primarily by performing the following activities: (i) providing our drilling rig, work crews, related equipment and services necessary to operate the rig (ii) delivering the drilling rig by mobilizing to and demobilizing from the drill location, and (iii) performing certain pre-operating activities, including rig preparation activities or equipment modifications required for the contract.  These services represent a single performance obligation under our drilling contracts with customers that is satisfied over time, the duration of which varies by contract.  At December 31, 2021, the drilling contract with the longest expected remaining duration, excluding unexercised options, extends through February 2028.

Disaggregation—Our contract drilling revenues, disaggregated by asset group and by country in which they were earned, were as follows (in millions):

	Year ended December 31, 2021								Year ended December 31, 2020								Year ended December 31, 2019
	U.S.		Norway		Other (a)		Total		U.S.		Norway		Other (a)		Total		U.S.		Norway		Other (a)		Total
Ultra-deepwater floaters	$	1,096	$	—	$	624	$	1,720	$	1,302	$	—	$	792	$	2,094	$	1,264	$	—	$	693	$	1,957
Harsh environment floaters		2		790		44		836		—		876		170		1,046		—		775		294		1,069
Deepwater floaters		—		—		—		—		—		—		—		—		—		—		7		7
Midwater floaters		—		—		—		—		—		—		12		12		—		—		55		55
Total contract drilling revenues	$	1,098	$	790	$	668	$	2,556	$	1,302	$	876	$	974	$	3,152	$	1,264	$	775	$	1,049	$	3,088

(a) Other represents the aggregate value for countries in which we operate that individually had attributable operating revenues representing less than 10 percent of consolidated operating revenues earned.

Major customers—For the year ended December 31, 2021, Shell plc (together with its affiliates, “Shell”) and Equinor ASA (together with its affiliates, “Equinor”) represented approximately 31 percent and 30 percent, respectively, of our consolidated operating revenues.  For the year ended December 31, 2020, Shell, Equinor and Chevron Corporation (together with its affiliates, “Chevron”) represented approximately 28 percent, 27 percent and 14 percent, respectively, of our consolidated operating revenues.  For the year ended December 31, 2019, Shell, Equinor and Chevron represented approximately 26 percent, 21 percent and 17 percent, respectively, of our consolidated operating revenues.

Contract liabilities—Contract liabilities for our contracts with customers were as follows (in millions):

	December 31,
	2021		2020
Deferred contract revenues, recorded in other current liabilities	$	83	$	133
Deferred contract revenues, recorded in other long-term liabilities		265		323
Total contract liabilities	$	348	$	456

Significant changes in contract liabilities were as follows (in millions):

	Years ended December 31,
	2021		2020
Total contract liabilities, beginning of period	$	456	$	529
Decrease due to recognition of revenues for goods and services		(149)		(184)
Increase due to goods and services transferred over time		41		111
Total contract liabilities, end of period	$	348	$	456

Performance obligations satisfied in prior periods—In June 2020, we entered into a settlement and mutual release agreement with a customer, which provided for the final settlement of disputes related to performance obligations satisfied in prior periods.  In connection with the settlement, among other things, our customer agreed to pay us $185 million in four equal installments through January 15, 2023.  In the year ended December 31, 2020, we recognized revenues of $177 million, representing the discounted value of the future payments, and recorded corresponding accounts receivable, net of imputed interest.  In the years ended December 31, 2021 and 2020, we received an aggregate cash payment of $46 million in scheduled installments under the arrangement.  At December 31, 2021 and 2020, the aggregate carrying amount of the related receivable was $90 million and $133 million, respectively, net of imputed interest, including $46 million and $45 million, respectively, recorded in accounts receivable, and $44 million and $88 million, respectively, recorded in other assets.

In the year ended December 31, 2019, we recognized revenues of $10 million for other performance obligations satisfied in prior periods due to certain revenues recognized on a cash basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Pre-operating costs—In the years ended December 31, 2021, 2020 and 2019, we recognized pre-operating costs of $48 million, $60 million and $18 million, respectively, recorded in operating and maintenance costs.  At December 31, 2021 and 2020, the unrecognized pre-operating costs to obtain contracts was $21 million and $20 million, respectively, recorded in other assets.

Note 6—Contract Intangible Assets

The gross carrying amount and accumulated amortization of our drilling contract intangible assets were as follows (in millions):

	Year ended December 31, 2021						Year ended December 31, 2020
	Gross				Net		Gross				Net
	carrying		Accumulated		carrying		carrying		Accumulated		carrying
	amount		amortization		amount		amount		amortization		amount
Drilling contract intangible assets
Balance, beginning of period	$	907	$	(514)	$	393	$	907	$	(299)	$	608
Amortization		—		(220)		(220)		—		(215)		(215)
Balance, end of period	$	907	$	(734)	$	173	$	907	$	(514)	$	393

As of December 31, 2021, the estimated future amortization over the expected remaining contract periods, the longest of which currently extends through March 2024, was as follows (in millions):

	Total
Years ending December 31,
2022	$	117
2023		52
2024		4
Total carrying amount of contract intangible assets	$	173

Note 7—Long-Lived Assets

Disaggregation—The aggregate carrying amount of our long-lived assets, including our property and equipment and our right-of-use assets, disaggregated by country in which they were located, was as follows (in millions):

	December 31,
	2021		2020
Long-lived assets
U.S.	$	5,779	$	6,007
Norway		3,379		3,560
Greece		3,162		3,294
Other countries (a)		5,293		5,347
Total long-lived assets	$	17,613	$	18,208

(a) Other countries represents the aggregate value for countries in which we operate that individually had attributable long-lived assets representing less than 10 percent of consolidated long-lived assets.

Because the majority of our assets are mobile, the geographic locations of such assets at the end of the periods are not necessarily indicative of the geographic distribution of the operating revenues generated by such assets during the periods presented.  Our international operations are subject to certain political and other uncertainties, including risks of war and civil disturbances or other market disrupting events, expropriation of equipment, repatriation of income or capital, taxation policies, and the general hazards associated with certain areas in which we operate.  Although we are organized under the laws of Switzerland, we have minimal assets located in Switzerland, and we do not conduct any operations or earn operating revenues in Switzerland.

Construction work in progress—The changes in our construction work in progress were as follows (in millions):

	Years ended December 31,
	2021		2020		2019
Construction work in progress, beginning of period	$	828	$	753	$	632
Capital expenditures
Newbuild construction program		174		143		129
Other equipment and construction projects		34		122		258
Total capital expenditures		208		265		387
Changes in accrued capital additions		13		(33)		20
Construction work in progress impaired		—		—		(5)
Property and equipment placed into service		(32)		(157)		(281)
Construction work in progress, end of period	$	1,017	$	828	$	753

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Impairments of assets held and used—During the year ended December 31, 2020, we identified indicators that the carrying amounts of our asset groups may not be recoverable.  Such indicators included significant declines in commodity prices and the market value of our stock, a reduction of expected demand for our drilling services as our customers announced reductions of capital investments in response to commodity prices and a reduction of projected dayrates.  As a result of our testing, we determined that the carrying amount of our midwater floater asset group was impaired.  In the year ended December 31, 2020, we recognized a loss of $31 million ($0.05 per diluted share), which had no tax effect, associated with the impairment of our midwater floater asset group.  We estimated the fair value of the rig and related assets in this asset group by applying the market approach using significant other observable inputs, representative of Level 2 fair value measurements, including the marketability of the rig and prices of comparable rigs that may be sold for scrap value.

Impairments of assets held for sale—In the year ended December 31, 2020, we recognized an aggregate loss of $556 million ($0.90 per diluted share), which had no tax effect, associated with the impairment of the ultra-deepwater floater GSF Development Driller II, the harsh environment floaters Polar Pioneer and Songa Dee and the midwater floaters Sedco 711, Sedco 714 and Transocean 712, along with related assets, which we determined were impaired at the time that we classified the assets as held for sale.  In the year ended December 31, 2019, we recognized an aggregate loss of $578 million ($0.94 per diluted share), which had no tax effect, associated with the impairment of the ultra-deepwater floaters Discoverer Deep Seas, Discoverer Enterprise and Discoverer Spirit, along with related assets, which we determined were impaired at the time we classified the assets as held for sale.  

We measured the impairment of the drilling units and related assets as the amount by which the carrying amount exceeded the estimated fair value less costs to sell.  We estimated the fair value of the assets using significant other observable inputs, representative of Level 2 fair value measurements, including indicative market values for the drilling units and related assets to be sold for scrap value or binding contracts to sell such assets for alternative purposes.  If we commit to plans to sell additional rigs for values below the respective carrying amounts, we will be required to recognize additional losses in future periods associated with the impairment of such assets.

Dispositions—During the year ended December 31, 2021, in connection with our efforts to dispose of non-strategic assets, we completed the sale of the harsh environment floater Leiv Eiriksson and related assets.  In the year ended December 31, 2021, we received aggregate net cash proceeds of $4 million and recognized an aggregate net loss of $57 million ($0.09 per diluted share), which had no tax effect, primarily associated with the disposal of these assets.  In the year ended December 31, 2021, we received aggregate net cash proceeds of $5 million and recognized an aggregate net loss of $5 million associated with the disposal of assets unrelated to rig sales.

During the year ended December 31, 2020, we completed the sale of the ultra-deepwater floater GSF Development Driller II, the harsh environment floaters Polar Pioneer, Songa Dee and Transocean Arctic and the midwater floaters Sedco 711, Sedco 714 and Transocean 712, along with related assets.  In the year ended December 31, 2020, we received aggregate net cash proceeds of $20 million and recognized an aggregate net loss of $61 million ($0.10 per diluted share), which had no tax effect, associated with the disposal of these assets.  In the year ended December 31, 2020, we received aggregate net cash proceeds of $4 million and recognized an aggregate net loss of $23 million associated with the disposal of assets unrelated to rig sales.

During the year ended December 31, 2019, we completed the sale of the ultra-deepwater floaters Deepwater Frontier, Deepwater Millennium, Discoverer Deep Seas, Discoverer Enterprise, Discoverer Spirit and Ocean Rig Paros, the harsh environment floater Eirik Raude, the deepwater floaters Jack Bates and Transocean 706 and the midwater floaters Actinia and Songa Delta, along with related assets.  In the year ended December 31, 2019, we received aggregate net cash proceeds of $64 million and recognized an aggregate net gain of $4 million ($0.01 per diluted share), which had no tax effect, associated with the disposal of these assets.  In the year ended December 31, 2019, we received aggregate net cash proceeds of $6 million and recognized an aggregate net loss of $16 million associated with the disposal of assets unrelated to rig sales.

Cancelled construction contracts—In the year ended December 31, 2019, we recognized income of $132 million, recorded in other income, net, associated with the cancellation of certain construction contracts acquired in December 2018 in connection with our acquisition of Ocean Rig UDW Inc., a Cayman Islands exempted company with limited liability, for the construction of two ultra-deepwater drillships.  Under the acquisition method of accounting for the business combination, the contract liabilities represented the amount by which the remaining payments due under the acquired contracts were above market construction rates for similar drilling units, measured as of the acquisition date.

Note 8—Leases

Overview—Our operating leases are principally for office space, storage facilities, operating equipment and land.  At December 31, 2021, our operating leases had a weighted-average discount rate of 6.4 percent and a weighted-average remaining lease term of 13.5 years.

Our finance lease for the ultra-deepwater drillship Petrobras 10000 has an implicit interest rate of 7.8 percent and requires scheduled monthly installments through the lease expiration in August 2029, after which we are obligated to acquire the drillship from the lessor for one dollar.  We recognize expense for the amortization of the right-of-use asset in depreciation and amortization.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Lease costs—The components of our lease costs were as follows (in millions):

	Years ended December 31,
Lease costs	2021		2020		2019
Short-term lease costs	$	17	$	27	$	13
Operating lease costs		12		13		25
Finance lease costs, amortization of right-of-use asset		20		21		21
Finance lease costs, interest on lease liability		33		36		39
Total lease costs	$	82	$	97	$	98

In the year ended December 31, 2019, we recognized a loss of $26 million, with no tax effect, associated with the impairment of right-of-use assets and leasehold improvements for certain office facilities that we vacated or committed to sublease.

Lease payments—Supplemental cash flow information for our leases was as follows (in millions):

	Years ended December 31,
	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		13	$	17	$	19
Operating cash flows from finance lease		37		36		39
Financing cash flows from finance lease		33		35		32

At December 31, 2021, the aggregate future minimum lease payments were as follows (in millions):

	Operating		Finance
	leases		lease
Years ending December 31,
2022	$	14	$	71
2023		13		70
2024		13		71
2025		13		70
2026		12		71
Thereafter		113		188
Total future minimum rental payment		178		541
Less amount representing imputed interest		(61)		(135)
Present value of future minimum rental payments		117		406
Current portion, recorded in other current liabilities		8		40
Long-term lease liabilities, recorded in other long-term liabilities	$	109	$	366

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Note 9—Debt

Overview

Outstanding debt—The aggregate principal amounts and aggregate carrying amounts, including the contractual interest payments of debt restructured in the year ended December 31, 2020 and unamortized debt-related balances, such as discounts, premiums and issue costs, were as follows (in millions):

		Principal amount				Carrying amount
		December 31,		December 31,		December 31,		December 31,
		2021		2020		2021		2020
6.375% Senior Notes due December 2021	(a)	$	—	$	38	$	—	$	38
5.52% Senior Secured Notes due May 2022	(b)		18		111		18		111
3.80% Senior Notes due October 2022	(a)		27		27		27		27
0.50% Exchangeable Senior Bonds due January 2023	(a)		140		463		140		462
5.375% Senior Secured Notes due May 2023	(c)		306		364		304		360
5.875% Senior Secured Notes due January 2024	(c)		435		585		430		577
7.75% Senior Secured Notes due October 2024	(c)		300		360		296		354
6.25% Senior Secured Notes due December 2024	(c)		313		375		309		369
6.125% Senior Secured Notes due August 2025	(c)		402		468		397		461
7.25% Senior Notes due November 2025	(d)		411		411		406		405
4.00% Senior Guaranteed Exchangeable Bonds due December 2025	(e)		294		—		264		—
7.50% Senior Notes due January 2026	(d)		569		569		565		565
2.50% Senior Guaranteed Exchangeable Bonds due January 2027	(e)		238		238		271		277
11.50% Senior Guaranteed Notes due January 2027	(e)		687		687		1,078		1,139
6.875% Senior Secured Notes due February 2027	(c)		550		550		544		542
8.00% Senior Notes due February 2027	(d)		612		612		607		606
7.45% Notes due April 2027	(a)		52		52		52		51
8.00% Debentures due April 2027	(a)		22		22		22		22
7.00% Notes due June 2028	(f)		261		261		265		266
7.50% Notes due April 2031	(a)		396		396		394		394
6.80% Senior Notes due March 2038	(a)		610		610		605		605
7.35% Senior Notes due December 2041	(a)		177		177		176		176
Total debt			6,820		7,376		7,170		7,807
Less debt due within one year
6.375% Senior Notes due December 2021	(a)		—		38		—		38
5.52% Senior Secured Notes due May 2022	(b)		18		93		18		92
3.80% Senior Notes due October 2022	(a)		27		—		27		—
5.375% Senior Secured Notes due May 2023	(c)		63		47		62		46
5.875% Senior Secured Notes due January 2024	(c)		83		83		80		80
7.75% Senior Secured Notes due October 2024	(c)		60		60		58		58
6.25% Senior Secured Notes due December 2024	(c)		62		62		61		60
6.125% Senior Secured Notes due August 2025	(c)		66		66		64		64
2.50% Senior Guaranteed Exchangeable Bonds due January 2027	(e)		—		—		6		6
11.50% Senior Guaranteed Notes due January 2027	(e)		—		—		70		61
6.875% Senior Secured Notes due February 2027	(c)		69		—		67		—
Total debt due within one year			448		449		513		505
Total long-term debt		$	6,372	$	6,927	$	6,657	$	7,302

(a) Transocean Inc., a 100 percent owned direct subsidiary of Transocean Ltd., is the issuer of the notes and debentures (the “Legacy Guaranteed Notes”).  The Legacy Guaranteed Notes are fully and unconditionally, jointly and severally, guaranteed by Transocean Ltd.

(b) The subsidiary issuer of the unregistered senior secured notes is a wholly owned indirect subsidiary of Transocean Inc.  The senior secured notes are fully and unconditionally guaranteed by the owner of the collateral rig.

(c) Each subsidiary issuer of the respective unregistered senior secured notes is a wholly owned indirect subsidiary of Transocean Inc.  The senior secured notes are fully and unconditionally, jointly and severally, guaranteed by Transocean Ltd., Transocean Inc. and, in each case, the owner of the respective collateral rig or rigs.

(d) Transocean Inc. is the issuer of the unregistered notes (collectively, the “Priority Guaranteed Notes”).  The guaranteed senior unsecured notes are fully and unconditionally, jointly and severally, guaranteed by Transocean Ltd. and certain wholly owned indirect subsidiaries of Transocean Inc. and rank equal in right of payment of all of our existing and future unsecured unsubordinated obligations.  Such notes are structurally senior to the Legacy Guaranteed Notes and the 7.00% notes due June 2028 and are structurally subordinate to the Senior Priority Guaranteed Notes, as defined below, to the extent of the value of the assets of the subsidiaries guaranteeing the notes.

(e) Transocean Inc. is the issuer of the unregistered notes (together, the “Senior Priority Guaranteed Notes”).  The priority guaranteed senior unsecured notes are fully and unconditionally, jointly and severally, guaranteed by Transocean Ltd. and certain wholly owned indirect subsidiaries of Transocean Inc. and rank equal in right of payment of all of our existing and future unsecured unsubordinated obligations.  Such notes are structurally senior to the Priority Guaranteed Notes to the extent of the value of the assets of the subsidiaries guaranteeing the notes.

(f) The subsidiary issuer of the registered notes is a wholly owned indirect subsidiary of Transocean Inc.  The notes are fully and unconditionally guaranteed by Transocean Inc.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Transocean Ltd. has no independent assets or operations, and its other subsidiaries not owned indirectly through Transocean Inc. are minor.  Transocean Inc. has no independent assets and operations, other than those related to its investments in non-guarantor operating companies and balances primarily pertaining to its cash and cash equivalents and debt.  Transocean Ltd. and Transocean Inc. are not subject to any significant restrictions on their ability to obtain funds from their consolidated subsidiaries by dividends, loans or capital distributions.

Indentures—The indentures that govern our debt generally contain covenants that, among other things, limit our ability to incur certain liens on our drilling units without equally and ratably securing the notes, to engage in certain sale and lease back transactions covering any of our drilling units, to allow our subsidiaries to incur certain additional debt, or to engage in certain merger, consolidation or reorganization transactions or to enter into a scheme of arrangement qualifying as an amalgamation.

The indentures that govern the 5.52% senior secured notes due May 2022 (the “5.52% Senior Secured Notes”), the 5.375% Senior Secured Notes due May 2023 (the “5.375% Senior Secured Notes”), the 5.875% senior secured notes due January 2024, the 7.75% senior secured notes due October 2024, the 6.25% senior secured notes due December 2024, the 6.125% senior secured notes due August 2025 and the 6.875% senior secured notes due February 2027 (the “6.875% Senior Secured Notes”) contain covenants that limit the ability of our subsidiaries that own or operate the collateral rigs to declare or pay dividends to their affiliates.

The indentures that govern the 4.00% Senior Guaranteed Exchangeable Bonds, the 2.50% Senior Guaranteed Exchangeable Bonds and the 0.50% Exchangeable Senior Bonds require such bonds to be repurchased upon the occurrence of certain fundamental changes and events, at specified prices depending on the particular fundamental change or event, which include changes and events related to certain (i) change of control events applicable to Transocean Ltd. or Transocean Inc., (ii) the failure of our shares to be listed or quoted on a national securities exchange and (iii) specified tax matters.

Interest rate adjustments—The interest rates for certain of our notes are subject to adjustment from time to time upon a change to the credit rating of our non-credit enhanced senior unsecured long-term debt.  At December 31, 2021, the interest rate in effect for the 3.80% senior notes due October 2022 and the 7.35% senior notes due December 2041 was 5.80 percent and 9.35 percent, respectively.

Scheduled maturities—At December 31, 2021, the scheduled maturities of our debt, including the principal installments and other installments, representing the contractual interest payments of previously restructured debt, were as follows (in millions):

	Principal		Other
	installments		installments		Total
Years ending December 31,
2022	$	448	$	76	$	524
2023		722		76		798
2024		786		77		863
2025		992		77		1,069
2026		652		78		730
Thereafter		3,220		39		3,259
Total installments of debt	$	6,820	$	423		7,243
Total unamortized debt-related balances, net						(73)
Total carrying amount of debt					$	7,170

Credit agreements

Secured Credit Facility—As of December 31, 2021, we have a $1.33 billion secured revolving credit facility established under a bank credit agreement (as amended from time to time, the “Secured Credit Facility”), which is scheduled to expire on June 22, 2023.  The Secured Credit Facility is guaranteed by Transocean Ltd. and certain wholly owned subsidiaries.  The Secured Credit Facility is secured by, among other things, a lien on the ultra-deepwater floaters Deepwater Asgard, Deepwater Corcovado, Deepwater Invictus, Deepwater Mykonos, Deepwater Orion, Deepwater Skyros, Development Driller III, Dhirubhai Deepwater KG2 and Discoverer Inspiration and the harsh environment floaters Transocean Barents and Transocean Spitsbergen, and at December 31, 2021, the aggregate carrying amount of which was $5.07 billion.  The maximum borrowing capacity will be reduced to $1.00 billion if, and so long as, our leverage ratio, measured as the aggregate principal amount of debt outstanding to earnings before interest, taxes, depreciation and amortization, exceeds 10.00 to 1.00.  The Secured Credit Facility contains covenants that, among other things, include maintenance of a minimum guarantee coverage ratio of 3.0 to 1.0, a minimum collateral coverage ratio of 2.1 to 1.0, a maximum debt to capitalization ratio of 0.60 to 1.00 and minimum liquidity of $500 million.  The Secured Credit Facility also restricts the ability of Transocean Ltd. and certain of our subsidiaries to, among other things, merge, consolidate or otherwise make changes to the corporate structure, incur liens, incur additional indebtedness, enter into transactions with affiliates and pay dividends and other distributions.

We may borrow under the Secured Credit Facility at either (1) the reserve adjusted London Interbank Offered Rate plus a margin (the “Secured Credit Facility Margin”), which ranges from 2.625 percent to 3.375 percent based on the credit rating of the Secured Credit Facility, or (2) the base rate specified in the credit agreement plus the Secured Credit Facility Margin, minus one percent per annum.  Throughout the term of the Secured Credit Facility, we pay a facility fee on the amount of the underlying commitment which ranges from 0.375 percent to 1.00 percent based on the credit rating of the Secured Credit Facility.  At December 31, 2021, based on the credit rating of

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

the Secured Credit Facility on that date, the Secured Credit Facility Margin was 3.375 percent and the facility fee was 0.875 percent.  At December 31, 2021, we had no borrowings outstanding, $17 million of letters of credit issued, and we had $1.32 billion of available borrowing capacity under the Secured Credit Facility.

Shipyard financing arrangement—In June 2021, Transocean Offshore Deepwater Holdings Limited, a Cayman Islands company and our wholly owned indirect subsidiary, entered into credit agreements with Jurong Shipyard Pte Ltd. establishing facilities (the “Shipyard Loans”) to finance all or a portion of the final payments expected to be owed to the shipyard upon delivery of the ultra-deepwater floaters Deepwater Atlas and Deepwater Titan.  The Shipyard Loans are guaranteed by Transocean Inc.  Borrowings under the Shipyard Loan for Deepwater Atlas will be secured by, among other security, a lien on the rig.  In certain circumstances, borrowings under the Shipyard Loan for Deepwater Titan may also be secured by, among other security, a lien on the rig.  We will repay the borrowings, together with interest of 4.5 percent per annum, according to the selected installment schedule over a maximum of a six-year period following delivery of the drilling rigs.  We have the right to prepay any outstanding borrowings, in full or in part, without penalty.  The Shipyard Loans contain covenants that, among other things, limit the ability of the subsidiary owners of the drilling rigs to incur certain types of additional indebtedness or make certain additional commitments or investments.  At December 31, 2021, we had no borrowings outstanding under the Shipyard Loans.

Exchangeable bonds

Exchange terms—At December 31, 2021, the (a) current exchange rates, expressed as the number of Transocean Ltd. shares per $1,000 note, (b) implied exchange prices per Transocean Ltd. share and (c) aggregate shares, expressed in millions, issuable upon exchange of our exchangeable bonds were as follows:

			Implied
	Exchange		exchange		Shares
	rate		price		issuable
0.50% Exchangeable Senior Bonds due January 2023		97.29756	$	10.28		13.6
4.00% Senior Guaranteed Exchangeable Bonds due December 2025		190.47620		5.25		56.0
2.50% Senior Guaranteed Exchangeable Bonds due January 2027		162.16260		6.17		38.6

The exchange rates of our exchangeable bonds, identified above, are subject to adjustment upon the occurrence of certain events.  The 0.50% Exchangeable Senior Bonds may be exchanged by holders into Transocean Ltd. shares at any time prior to the close of business on the business day immediately preceding the maturity date.  The 2.50% Senior Guaranteed Exchangeable Bonds may be exchanged by holders into Transocean Ltd. shares at any time prior to the close of business on the second business day immediately preceding the maturity date or redemption date.  The 4.00% Senior Guaranteed Exchangeable Bonds may be exchanged by holders at any time prior to the close of business on the second business day immediately preceding the maturity date and, at our election, such exchange may be settled by delivering cash, Transocean Ltd. shares or a combination of cash and shares.

Effective interest rates and fair values—At December 31, 2021, the effective interest rates and estimated fair values of our exchangeable bonds were as follows (in millions, except effective interest rates):

	Effective		Fair
	interest rate		value
0.50% Exchangeable Senior Bonds due January 2023		0.5%	$	119
4.00% Senior Guaranteed Exchangeable Bonds due December 2025		6.9%		278
2.50% Senior Guaranteed Exchangeable Bonds due January 2027		0.0%		196

We estimated the fair values of the exchangeable debt instruments, including the exchange features, by employing a binomial lattice model using significant other observable inputs, representative of Level 2 fair value measurements, including the terms and credit spreads of our debt and the expected volatility of the market price for our shares.

Related balances—At December 31, 2021 and 2020, the premium associated with the original issuance of the 0.50% Exchangeable Senior Bonds had a carrying amount of $172 million, recorded in equity as a component of additional paid-in capital.

Debt issuance

Senior guaranteed exchangeable bonds—On February 26, 2021, we issued $294 million aggregate principal amount of the 4.00% Senior Guaranteed Exchangeable Bonds and made an aggregate cash payment of $11 million in private exchanges (collectively, the “2021 Private Exchange”) for $323 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds.  In the year ended December 31, 2021, as a result of the 2021 Private Exchange, we recognized a gain of $51 million ($0.08 per diluted share), with no tax effect, associated with the retirement of debt (see “—Debt restructuring, repayment and retirement”).  The initial carrying amount of the 4.00% Senior Guaranteed Exchangeable Bonds, measured at the estimated fair value on the date of issuance, was $260 million.  We estimated the fair value of the exchangeable debt instrument, including the exchange feature, by employing a binomial lattice model using significant other observable inputs, representative of Level 2 fair value measurements, including the terms and credit spreads of our debt and expected volatility of the market price for our shares.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

On August 14, 2020, we issued $238 million aggregate principal amount of 2.50% Senior Guaranteed Exchangeable Bonds in non-cash private exchanges (collectively, the “2020 Private Exchange”) for $397 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds.  In the year ended December 31, 2020, as a result of the 2020 Private Exchange, we recognized a gain of $72 million ($0.12 per diluted share), with no tax effect, associated with the restructuring of debt (see “—Debt restructuring, repayment and retirement”).  We may redeem all or a portion of the 2.50% Senior Guaranteed Exchangeable Bonds (i) on or after August 14, 2022, if certain conditions related to the price of our shares have been satisfied, at a price equal to 100 percent of the aggregate principal amount and (ii) on or after August 14, 2023, at specified redemption prices.  We recorded the conversion feature of the 2.50% Senior Guaranteed Exchangeable Bonds, measured at its estimated fair value of $46 million, to additional paid-in capital.  We estimated the fair value by employing a binomial lattice model using significant other observable inputs, representative of Level 2 fair value measurements, including the expected volatility of the market price for our shares.

Related party transactions—In August 2020, Perestroika AS, an entity affiliated with one of our directors that beneficially owns approximately 10 percent of our shares, exchanged $356 million aggregate principal amount of the 0.50% Exchangeable Senior Bonds for $213 million aggregate principal amount of 2.50% Senior Guaranteed Exchangeable Bonds.  Perestroika AS has certain registration rights related to its shares and shares that may be issued in connection with any exchange of its 2.50% Senior Guaranteed Exchangeable Bonds.  At December 31, 2021 and 2020, Perestroika AS held $213 million aggregate principal amount of the 2.50% Senior Guaranteed Exchangeable Bonds.

Guaranteed senior unsecured notes—On January 17, 2020, we issued $750 million aggregate principal amount of 8.00% senior notes due February 2027 (the “8.00% Senior Notes”), and we received aggregate cash proceeds of $743 million, net of issue costs.  We may redeem all or a portion of the 8.00% Senior Notes on or prior to February 1, 2023 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.

Priority guaranteed senior unsecured notes—On September 11, 2020, we issued $687 million aggregate principal amount of 11.50% senior guaranteed notes due January 2027 (the “11.50% Senior Guaranteed Notes”) in non-cash exchange offers, pursuant to an exchange offer memorandum, dated August 10, 2020, as supplemented, for an aggregate principal amount of $1.5 billion of several series of our existing debt securities that were validly tendered and accepted for purchase (the “2020 Exchange Offers” and, together with the 2020 Private Exchange, the “2020 Exchange Transactions”).  In the year ended December 31, 2020, as a result of the 2020 Exchange Offers, we recognized a gain of $355 million ($0.58 per diluted share), with no tax effect, associated with the restructuring of debt (see “—Debt restructuring, repayment and retirement”).  We may redeem all or a portion of the 11.50% Senior Guaranteed Notes prior to July 30, 2023 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.  We may also use the net cash proceeds of certain equity offerings by Transocean Ltd. to redeem, on one or more occasions prior to July 30, 2023, up to a maximum of 40 percent of the original aggregate principal amount of the 11.50% Senior Guaranteed Notes, subject to certain adjustments, at a redemption price equal to 111.50 percent of the aggregate principal amount.

Senior secured notes—On February 1, 2019, we issued $550 million aggregate principal amount of 6.875% Senior Secured Notes, and we received $539 million aggregate cash proceeds, net of discount and issue costs.  The 6.875% Senior Secured Notes are secured by the assets and earnings associated with the ultra-deepwater floater Deepwater Poseidon and the equity of the wholly owned subsidiaries that own or operate the collateral rig.  Additionally, we are required to maintain certain balances in restricted cash accounts to satisfy debt service requirements.  We are required to pay semiannual installments of principal and interest.  We may redeem all or a portion of the 6.875% Senior Secured Notes on or prior to February 1, 2022 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.

On May 24, 2019, we issued $525 million aggregate principal amount of 5.375% Senior Secured Notes, and we received $517 million aggregate cash proceeds, net of discount and issue costs.  The 5.375% Senior Secured Notes are secured by the assets and earnings associated with the harsh environment floaters Transocean Endurance and Transocean Equinox and the equity of the wholly owned subsidiaries that own or operate the collateral rigs.  Additionally, we are required to maintain certain balances in restricted cash accounts to satisfy debt service requirements.  We are required to pay semiannual installments of principal and interest.  We may redeem all or a portion of the 5.375% Senior Secured Notes on or prior to May 15, 2021 at a price equal to 100 percent of the aggregate principal amount plus a make-whole premium, and subsequently, at specified redemption prices.

Encumbered assets—At December 31, 2021, we had restricted cash and cash equivalents of $409 million deposited in restricted accounts to satisfy debt service and reserve requirements for the senior secured notes.  At December 31, 2021, the rigs encumbered for the senior secured notes, including Deepwater Conqueror, Deepwater Pontus, Deepwater Proteus, Deepwater Thalassa, Deepwater Poseidon, Transocean Enabler, Transocean Encourage, Transocean Endurance and Transocean Equinox, had an aggregate carrying amount of $5.93 billion.  We will be required to redeem the senior secured notes at a price equal to 100 percent of the aggregate principal amount without a make-whole premium, upon the occurrence of certain events related to the respective collateral rigs and related drilling contracts.

Debt restructuring, repayment and retirement

Restructuring and early retirement—During the years ended December 31, 2021, 2020 and 2019, we restructured or retired certain notes as a result of exchange offers, private exchanges, redemption, tender offers and open market repurchases.  We recorded the

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

2020 Exchange Transactions completed in August 2020 and September 2020 under ASC 470-60, Troubled Debt Restructuring by Debtors.  The aggregate principal amounts, cash payments and recognized gain or loss for such transactions were as follows (in millions):

	Year ended December 31, 2021						Year ended December 31, 2020										Year ended December 31, 2019
	Exchange		Repurchase		Total		Exchange		Redeem		Tender		Repurchase		Total		Tender		Repurchase		Total
6.50% Senior Notes due November 2020	$	—	$	—	$	—	$	—	$	—	$	38	$	15	$	53	$	57	$	23	$	80
6.375% Senior Notes due December 2021		—		—		—		37		—		77		69		183		63		43		106
3.80% Senior Notes due October 2022		—		—		—		136		—		10		16		162		190		32		222
0.50% Exchangeable Senior Bonds due January 2023		323		—		323		397		—		—		4		401		—		—		—
5.375% Senior Secured Notes due May 2023		—		11		11		—		—		103		43		146		—		—		—
9.00% Senior Notes due July 2023		—		—		—		—		714		—		—		714		200		336		536
5.875% Senior Secured Notes due January 2024		—		68		68		—		—		—		—		—		—		—		—
7.25% Senior Notes due November 2025		—		—		—		207		—		132		—		339		—		—		—
7.50% Senior Notes due January 2026		—		—		—		181		—		—		—		181		—		—		—
8.00% Senior Notes due February 2027		—		—		—		138		—		—		—		138		—		—		—
7.45% Notes due April 2027		—		—		—		35		—		—		—		35		—		—		—
8.00% Debentures due April 2027		—		—		—		35		—		—		—		35		—		—		—
7.00% Notes due June 2028		—		—		—		39		—		—		—		39		—		—		—
7.50% Notes due April 2031		—		—		—		192		—		—		—		192		—		—		—
6.80% Senior Notes due March 2038		—		—		—		390		—		—		—		390		—		—		—
7.35% Senior Notes due December 2041		—		—		—		123		—		—		—		123		—		—		—
Aggregate principal amount restructured or retired	$	323	$	79	$	402	$	1,910	$	714	$	360	$	147	$	3,131	$	510	$	434	$	944
Aggregate cash payment	$	11	$	79	$	90	$	10	$	767	$	222	$	110	$	1,109	$	522	$	449	$	971
Aggregate principal amount of debt issued in exchanges	$	294	$	—	$	294	$	925	$	—	$	—	$	—	$	925	$	—	$	—	$	—
Aggregate net gain (loss)	$	51	$	—	$	51	$	427	$	(65)	$	135	$	36	$	533	$	(18)	$	(23)	$	(41)

Scheduled maturities and installments—On the scheduled maturity date of December 15, 2021, we made a cash payment of $38 million to repay an equivalent aggregate principal amount of the outstanding 6.375% senior notes due December 2021.  On the scheduled maturity date of November 16, 2020, we made a cash payment of $153 million to repay an equivalent aggregate principal amount of the outstanding 6.50% senior notes due November 2020.  In the years ended December 31, 2021, 2020 and 2019, we made an aggregate cash payment of $478 million, $375 million and $354 million, respectively, to repay other indebtedness in scheduled installments.

Note 10—Postemployment Benefit Plans

Defined contribution plans

We sponsor defined contribution plans for our employees in most markets in which we operate worldwide, the most significant of which were as follows: (1) a qualified savings plan covering certain eligible employees working in the U.S., (2) various savings plans covering eligible employees working in Norway, (3) a non-qualified savings plan covering certain eligible employees working outside the U.S., the United Kingdom (“U.K.”) and Norway and (4) a qualified savings plan covering certain eligible employees working in the U.K.  In the years ended December 31, 2021, 2020 and 2019, we recognized expense of $52 million, $56 million and $52 million, respectively, related to our defined contribution plans, recorded in the same financial statement line item as cash compensation paid to the respective employees.

Defined benefit pension and other postemployment benefit plans

Overview—As of December 31, 2021, we had defined benefit plans in the U.S., including three funded and three unfunded defined benefit plans (the “U.S. Plans”), and in the U.K., we had one funded defined benefit plan (the “U.K. Plan”).  During the year ended December 31, 2021, as required by local authorities, we terminated our two remaining plans in Norway (together with the U.K. Plan, the “Non-U.S. Plans”).  We also maintain certain unfunded other postemployment benefit plans (collectively, the “OPEB Plans”), under which benefits to eligible participants diminish during a phase-out period ending December 31, 2025.  We maintain the benefit obligations under our plans until they are fully satisfied.

Net periodic benefit costs—We estimated our net periodic benefit costs using the following weighted-average assumptions:

	Year ended December 31, 2021						Year ended December 31, 2020						Year ended December 31, 2019
	U.S.		Non-U.S.		OPEB		U.S.		Non-U.S.		OPEB		U.S.		Non-U.S.		OPEB
	Plans		Plans		Plans		Plans		Plans		Plans		Plans		Plans		Plans
Discount rate	2.60	%	1.50	%	1.21	%	3.27	%	2.10	%	2.39	%	4.32	%	2.86	%	3.56	%
Expected rate of return	5.51	%	3.20	%	na		5.90	%	3.10	%	na		6.20	%	4.39	%	na

“na” means not applicable.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Net periodic benefit costs recognized included the following components (in millions):

	Year ended December 31, 2021								Year ended December 31, 2020								Year ended December 31, 2019
	U.S.		Non-U.S.		OPEB				U.S.		Non-U.S.		OPEB				U.S.		Non-U.S.		OPEB
	Plans		Plans		Plans		Total		Plans		Plans		Plans		Total		Plans		Plans		Plans		Total
Net periodic benefit costs
Service cost	$	—	$	—	$	—	$	—	$	—	$	1	$	—	$	1	$	—	$	7	$	—	$	7
Interest cost		47		6		—		53		55		8		—		63		63		10		1		74
Expected return on plan assets		(66)		(13)		—		(79)		(67)		(14)		—		(81)		(71)		(17)		—		(88)
Settlements and curtailments		—		(2)		—		(2)		1		12		—		13		1		2		—		3
Actuarial loss, net		11		1		—		12		9		1		1		11		3		—		—		3
Prior service gain, net		—		—		(2)		(2)		—		—		(2)		(2)		—		—		(2)		(2)
Net periodic benefit costs (income)	$	(8)	$	(8)	$	(2)	$	(18)	$	(2)	$	8	$	(1)	$	5	$	(4)	$	2	$	(1)	$	(3)

Funded status—We estimated our benefit obligations using the following weighted-average assumptions:

	December 31, 2021						December 31, 2020
	U.S.		U.K.		OPEB		U.S.		Non-U.S.		OPEB
	Plans		Plan		Plans		Plans		Plans		Plans
Discount rate	2.91	%	1.90	%	1.83	%	2.60	%	1.50	%	1.21	%
Expected long-term rate of return	4.82	%	2.00	%	na		5.51	%	3.20	%	na

“na” means not applicable.

The changes in projected benefit obligation, plan assets and funded status and the amounts recognized on our consolidated balance sheets were as follows (in millions):

	Year ended December 31, 2021								Year ended December 31, 2020
	U.S.		Non-U.S.		OPEB				U.S.		Non-U.S.		OPEB
	Plans		Plans		Plans		Total		Plans		Plans		Plans		Total
Change in projected benefit obligation
Projected benefit obligation, beginning of period	$	1,825	$	384	$	16	$	2,225	$	1,696	$	395	$	17	$	2,108
Actuarial losses (gains), net		(72)		(21)		(1)		(94)		148		46		1		195
Service cost		—		—		—		—		—		1		—		1
Interest cost		47		6		—		53		55		8		—		63
Currency exchange rate changes		—		(2)		—		(2)		—		9		—		9
Benefits paid		(76)		(17)		(2)		(95)		(72)		(24)		(2)		(98)
Settlements		—		(2)		—		(2)		(2)		(52)		—		(54)
Plan amendment		—		—		—		—		—		1		—		1
Projected benefit obligation, end of period		1,724		348		13		2,085		1,825		384		16		2,225
Change in plan assets
Fair value of plan assets, beginning of period		1,565		420		—		1,985		1,369		430		—		1,799
Actual return on plan assets		131		29		—		160		267		50		—		317
Currency exchange rate changes		—		(3)		—		(3)		—		6		—		6
Employer contributions		1		7		2		10		3		9		2		14
Benefits paid		(76)		(17)		(2)		(95)		(72)		(24)		(2)		(98)
Settlements		—		(2)		—		(2)		(2)		(51)		—		(53)
Fair value of plan assets, end of period		1,621		434		—		2,055		1,565		420		—		1,985
Funded status, end of period	$	(103)	$	86	$	(13)	$	(30)	$	(260)	$	36	$	(16)	$	(240)
Balance sheet classification, end of period:
Pension asset, non-current	$	16	$	86	$	—	$	102	$	—	$	37	$	—	$	37
Pension liability, current		(1)		—		(3)		(4)		(1)		(1)		(3)		(5)
Pension liability, non-current		(118)		—		(10)		(128)		(259)		—		(13)		(272)
Accumulated other comprehensive loss (income), before taxes		95		42		(10)		127		242		80		(10)		312
Accumulated benefit obligation, end of period	$	1,724	$	348	$	13	$	2,085	$	1,825	$	384	$	16	$	2,225

Certain amounts related to plans with a projected benefit obligation in excess of plan assets were as follows (in millions):

	December 31, 2021								December 31, 2020
	U.S.		U.K.		OPEB				U.S.		Non-U.S.		OPEB
	Plans		Plan		Plans		Total		Plans		Plans		Plans		Total
Projected benefit obligation	$	140	$	—	$	13	$	153	$	1,825	$	2	$	16	$	1,843
Fair value of plan assets		20		—		—		20		1,565		1		—		1,566

Certain amounts related to plans with an accumulated benefit obligation in excess of plan assets were as follows (in millions):

	December 31, 2021								December 31, 2020
	U.S.		U.K.		OPEB				U.S.		Non-U.S.		OPEB
	Plans		Plan		Plans		Total		Plans		Plans		Plans		Total
Accumulated benefit obligation	$	140	$	—	$	13	$	153	$	1,825	$	2	$	16	$	1,843
Fair value of plan assets		20		—		—		20		1,565		1		—		1,566

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The amounts in accumulated other comprehensive loss (income) that have not been recognized were as follows (in millions):

	December 31, 2021								December 31, 2020
	U.S.		U.K.		OPEB				U.S.		Non-U.S.		OPEB
	Plans		Plan		Plans		Total		Plans		Plans		Plans		Total
Actuarial loss, net	$	95	$	40	$	—	$	135	$	242	$	78	$	2	$	322
Prior service cost, net		—		2		(10)		(8)		—		2		(12)		(10)
Accumulated other comprehensive loss (income), before taxes	$	95	$	42	$	(10)	$	127	$	242	$	80	$	(10)	$	312

Plan assets—The weighted-average target and actual allocations of assets for the funded defined benefit plans were as follows:

	December 31, 2021								December 31, 2020
	Target allocation				Actual allocation				Target allocation				Actual allocation
	U.S.		U.K.		U.S.		U.K.		U.S.		Non-U.S.		U.S.		Non-U.S.
	Plans		Plan		Plans		Plan		Plans		Plans		Plans		Plans
Equity securities	38	%	19	%	38	%	19	%	50	%	27	%	55	%	25	%
Fixed income securities	62	%	81	%	62	%	80	%	50	%	73	%	45	%	74	%
Other investments	—	%	—	%	—	%	1	%	—		—	%	—		1	%
Total	100	%	100	%	100	%	100	%	100	%	100	%	100	%	100	%

We periodically review our investment policies, plan assets and asset allocation strategies to evaluate performance relative to specified objectives.  In determining our asset allocation strategies for the U.S. Plans, we review the results of regression models to assess the most appropriate target allocation for each plan, given the plan’s status, demographics and duration.  For the U.K. Plan, the plan trustees establish the asset allocation strategies consistent with the regulations of the U.K. pension regulators and in consultation with financial advisors and company representatives.  Investment managers for the U.S. Plans and the U.K. Plan are given established ranges within which the investments may deviate from the target allocations.

The investments for the funded defined benefit plans were categorized as follows (in millions):

	December 31, 2021
	Significant observable inputs						Significant other observable inputs						Total
	U.S.		U.K.				U.S.		U.K.				U.S.		U.K.
	Plans		Plan		Total		Plans		Plan		Total		Plans		Plan		Total
Mutual funds
U.S. equity funds	$	421	$	—	$	421	$	—	$	—	$	—	$	421	$	—	$	421
Non-U.S. equity funds		184		—		184		7		85		92		191		85		276
Bond funds		999		—		999		4		346		350		1,003		346		1,349
Total mutual funds		1,604		—		1,604		11		431		442		1,615		431		2,046
Other investments
Cash and money market funds		6		3		9		—		—		—		6		3		9
Total investments	$	1,610	$	3	$	1,613	$	11	$	431	$	442	$	1,621	$	434	$	2,055

	December 31, 2020
	Significant observable inputs						Significant other observable inputs						Total
	U.S.		Non-U.S.				U.S.		Non-U.S.				U.S.		Non-U.S.
	Plans		Plans		Total		Plans		Plans		Total		Plans		Plans		Total
Mutual funds
U.S. equity funds	$	586	$	—	$	586	$	—	$	—	$	—	$	586	$	—	$	586
Non-U.S. equity funds		263		—		263		7		103		110		270		103		373
Bond funds		699		—		699		4		310		314		703		310		1,013
Total mutual funds		1,548		—		1,548		11		413		424		1,559		413		1,972
Other investments
Cash and money market funds		6		6		12		—		—		—		6		6		12
Investment contracts		—		—		—		—		1		1		—		1		1
Total other investments		6		6		12		—		1		1		6		7		13
Total investments	$	1,554	$	6	$	1,560	$	11	$	414	$	425	$	1,565	$	420	$	1,985

We estimated the fair values of the plan assets by applying the market approach, as categorized above, using either (i) significant observable inputs, representative of Level 1 fair value measurements, including market prices of actively traded funds, or (ii) significant other observable inputs, representative of Level 2 fair value measurements, including market prices of the underlying securities in the collective trust funds.  The U.S. Plans and the U.K. Plan invest in passively and actively managed funds that are referenced to or benchmarked against market indices.  The plan investment managers have discretion to select the securities held within each asset category.  Given this discretion, the managers may occasionally invest in our debt or equity securities and may hold either long or short positions in such securities.  Since plan investment managers are required to maintain well diversified portfolios, the actual investment in our securities would be immaterial relative to asset categories and the overall plan assets.

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Funding contributions and benefit payments—In the years ended December 31, 2021, 2020 and 2019, we made an aggregate contribution of $10 million, $14 million and $22 million, respectively, to the defined benefit pension plans and the OPEB Plans using our cash flows from operations.  In the year ending December 31, 2022, we expect to make an aggregate contribution of $4 million, including $1 million and $3 million to the defined benefit pension plans and the OPEB Plans, respectively.

The projected benefits payments were as follows (in millions):

	U.S.		U.K.		OPEB
	Plans		Plan		Plans		Total
Years ending December 31,
2022	$	82	$	6	$	3	$	91
2023		83		6		3		92
2024		83		6		3		92
2025		84		7		2		93
2026		84		8		1		93
2027 - 2031		424		52		1		477

Note 11—Income Taxes

Overview—Transocean Ltd., a holding company and Swiss resident, is subject to Swiss federal, cantonal and communal income tax.  For Swiss income taxes, however, qualifying net dividend income and net capital gains on the sale of qualifying investments in subsidiaries are exempt from taxation.  Consequently, there is not a direct relationship between our Swiss earnings before income taxes and our Swiss income tax expense.

Tax provision and rate—In the years ended December 31, 2021, 2020 and 2019, our effective tax rate was (25.7) percent, (5.1) percent and (4.9) percent, respectively, based on loss before income tax expense.  The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures.

The components of our income tax provision (benefit) were as follows (in millions):

	Years ended December 31,
	2021		2020		2019
Current tax benefit	$	(7)	$	(33)	$	(189)
Deferred tax expense		128		60		248
Income tax expense	$	121	$	27	$	59

A reconciliation of the income tax benefit computed at the Swiss holding company federal statutory rate of 7.83% and our reported consolidated income tax expense was as follows (in millions):

	Years ended December 31,
	2021		2020		2019
Income tax benefit at Swiss federal statutory rate	$	(36)	$	(42)	$	(94)
Changes in valuation allowance		1,167		(31)		37
Earnings subject to rates different than the Swiss federal statutory rate		78		82		189
Deemed profits taxes		17		19		22
Jurisdictional ownership changes of certain assets		16		—		—
Withholding taxes		10		6		11
Losses on impairment		5		52		35
Changes in unrecognized tax benefits, net		(43)		(15)		(268)
Swiss Federal Act on Tax Reform and AHV Financing		(1,095)		—		—
Base erosion and anti-abuse tax		—		5		21
U.S. Coronavirus Aid, Relief, and Economic Security Act		—		(28)		—
Operating structural changes		—		—		98
Other, net		2		(21)		8
Income tax expense	$	121	$	27	$	59

In January 2020, Switzerland made effective the Federal Act on Tax Reform and AHV Financing (“TRAF”), which will subject us to ordinary taxation, effective January 1, 2022, following the expiration of our transition rulings.  In November 2021, we reached an agreement with the Swiss tax authorities regarding the manner by which TRAF will apply to certain Swiss subsidiaries, which will allow us to access historic depreciation and costs related to financing assets not previously deducted on Swiss tax returns, which can be apportioned to offset taxable income based on the remaining useful lives of the rigs and financing assets.  In the year ended December 31, 2021, we recorded a deferred tax liability of $238 million and a deferred tax asset of $1.33 billion, offset with a valuation allowance of $1.17 billion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

The Coronavirus Aid, Relief, and Economic Security Act, enacted in March 2020, made certain changes to U.S. tax law, including, among others, extending up to five years the carryback period for net operating losses generated between December 31, 2017 and January 1, 2021.  In the year ended December 31, 2020, we recognized an income tax benefit of $28 million related to the carryback of our net operating losses under this provision.

In the year ended December 31, 2019, as a result of the U.S. base erosion and anti-abuse tax, we recognized income tax expense of $21 million related to the bareboat charter structure of our U.S. operations, a significant portion of which was contractually reimbursed by our customers under a change-in-law provision in our drilling contracts.

Deferred taxes—The significant components of our deferred tax assets and liabilities were as follows (in millions):

	December 31,
	2021		2020
Deferred tax assets
Swiss historic depreciation and financing asset costs	$	1,333	$	—
Net operating loss carryforwards		915		809
Interest expense limitation		67		72
United Kingdom charter limitation		53		40
Accrued expenses		23		18
Tax credits		19		21
Deferred income		7		14
Accrued payroll costs not currently deductible		2		46
Loss contingencies		2		3
Other		31		27
Valuation allowance		(1,820)		(685)
Total deferred tax assets		632		365
Deferred tax liabilities
Depreciation		(1,052)		(658)
Contract intangible amortization		(11)		(6)
Other		(9)		(7)
Total deferred tax liabilities		(1,072)		(671)
Deferred tax assets (liabilities), net	$	(440)	$	(306)

As of December 31, 2021, we include taxes related to the earnings of all of our subsidiaries since we no longer consider the earnings of any of our subsidiaries to be indefinitely reinvested.

At December 31, 2021 and 2020, our deferred tax assets included U.S. foreign tax credits of $19 million and $21 million, respectively, which will expire between 2024 and 2031.  Deferred tax assets related to our net operating losses were generated in various worldwide tax jurisdictions.  At December 31, 2021, our net deferred tax assets related to our net operating loss carryforwards included $668 million, which do not expire, and $247 million, which will expire between 2022 and 2038.

As of December 31, 2021, our consolidated cumulative loss incurred over the recent three-year period represented significant objective negative evidence for the evaluation of the realizability of our deferred tax assets.  Although such evidence has limited our ability to consider other subjective evidence, we evaluate each jurisdiction separately.  We consider objective evidence, such as contract backlog activity, in jurisdictions in which we have profitable contracts, and the ability to carryback losses or utilize losses against potential exposures.  If estimated future taxable income changes during the carryforward periods or if the cumulative loss is no longer present, we may adjust the amount of deferred tax assets that we expect to realize.  At December 31, 2021 and 2020, due to uncertainty of realization, we had a valuation allowance of $1.82 billion and $685 million, respectively, on net operating losses and other deferred tax assets due to the uncertainty of realization.

Unrecognized tax benefits—The changes to unrecognized tax benefits, excluding interest and penalties that we recognize as a component of income tax expense, were as follows (in millions):

	Years ended December 31,
		2021		2020		2019
Balance, beginning of period	$	378	$	335	$	408
Additions for current year tax positions		28		90		144
Additions for prior year tax positions		46		11		6
Reductions related to statute of limitation expirations and changes in law		(19)		(7)		(138)
Reductions due to settlements		(31)		—		(19)
Reductions for prior year tax positions		—		(51)		(66)
Balance, end of period	$	402	$	378	$	335

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Our unrecognized tax benefits, including related interest and penalties that we recognize as a component of income tax expense, were as follows (in millions):

	December 31,
		2021		2020
Unrecognized tax benefits, excluding interest and penalties	$	402	$	378
Interest and penalties		33		41
Unrecognized tax benefits, including interest and penalties	$	435	$	419

In the years ended December 31, 2021, 2020 and 2019, we recognized, as a component of our income tax provision, expense of $8 million, expense of $7 million and benefit of $72 million, respectively, related to interest and penalties associated with our unrecognized tax benefits.  As of December 31, 2021, we have unrecognized benefits of $435 million, including interest and penalties, against which we have recorded net operating loss deferred tax assets of $320 million, resulting in net unrecognized tax benefits of $115 million, including interest and penalties, that upon reversal would favorably impact our effective tax rate.  During the year ending December 31, 2022, it is reasonably possible that our existing liabilities for unrecognized tax benefits may increase or decrease, primarily due to the progression of open audits and the expiration of statutes of limitation.  However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

Tax positions and returns—We conduct operations through our various subsidiaries in countries throughout the world.  Each country has its own tax regimes with varying nominal rates, deductions and tax attributes that are subject to changes resulting from new legislation, interpretation or guidance.  From time to time, as a result of these changes, we may revise previously evaluated tax positions, which could cause us to adjust our recorded tax assets and liabilities.  Tax authorities in certain jurisdictions are examining our tax returns and, in some cases, have issued assessments.  We intend to defend our tax positions vigorously.  Although we can provide no assurance as to the outcome of the aforementioned changes, examinations or assessments, we do not expect the ultimate liability to have a material adverse effect on our condensed consolidated statement of financial position or results of operations; however, it could have a material adverse effect on our condensed consolidated statement of cash flows.

Brazil tax investigations—In December 2005, the Brazilian tax authorities began issuing tax assessments with respect to our tax returns for the years 2000 through 2004.  In May 2014, the Brazilian tax authorities issued an additional tax assessment for the years 2009 and 2010.  We filed protests with the Brazilian tax authorities for the assessments and are engaged in the appeals process, and a portion of two cases were favorably closed.  As of December 31, 2021, the remaining aggregate tax assessment, including interest and penalties, was for corporate income tax of BRL 638 million, equivalent to approximately $115 million, and indirect tax of BRL 110 million, equivalent to $20 million.  We believe our returns are materially correct as filed, and we are vigorously contesting these assessments.  An unfavorable outcome on these proposed assessments could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Note 12—Loss Per Share

The computation of basic and diluted loss per share was as follows (in millions, except per share data):

	Years ended December 31,
	2021		2020		2019
Numerator for loss per share, basic and diluted
Net loss attributable to controlling interest	$	(592)	$	(567)	$	(1,255)
Denominator for loss per share, basic and diluted
Weighted-average shares outstanding		636		614		611
Effect of share-based awards		1		1		1
Weighted-average shares for per share calculation		637		615		612
Loss per share, basic and diluted	$	(0.93)	$	(0.92)	$	(2.05)

In the years ended December 31, 2021, 2020 and 2019, we excluded from the calculation 12.6 million, 10.8 million and 12.0 million share-based awards, respectively, since the effect would have been anti-dilutive.  In the years ended December 31, 2021, 2020 and 2019, we excluded from the calculation 104.4 million, 84.0 million and 84.0 million shares, respectively, issuable upon conversion of the 0.50% Exchangeable Senior Bonds, the 2.50% Senior Guaranteed Exchangeable Bonds and the 4.00% Senior Guaranteed Exchangeable Bonds since the effect would have been anti-dilutive.

Note 13—Commitments and Contingencies

Purchase and service agreement obligations

We have purchase obligations with shipyards and other contractors primarily related to our newbuild construction programs.  We also have long-term service agreements with original equipment manufacturers to provide services and parts, primarily related to our pressure

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

control systems and drilling systems.  The future payments required under our service agreements were estimated based on our projected operating activity and may vary subject to actual operating activity.  At December 31, 2021, the aggregate future payments required under our purchase obligations and our service agreement obligations were as follows (in millions):

			Service
	Purchase		agreement
	obligations		obligations
Years ending December 31,
2022	$	950	$	116
2023		52		121
2024		—		126
2025		—		130
2026		—		134
Thereafter		—		173
Total	$	1,002	$	800

Letters of credit and surety bonds

At December 31, 2021 and 2020, we had outstanding letters of credit totaling $18 million and $24 million, respectively, issued under various committed and uncommitted credit lines provided by banks to guarantee various contract bidding, performance activities and customs obligations.  At December 31, 2021 and 2020, we also had outstanding surety bonds totaling $146 million and $153 million, respectively, to secure customs obligations related to the importation of our rigs and certain performance and other obligations.  At December 31, 2021 and 2020, the aggregate cash collateral held by institutions to secure our letters of credit and surety bonds was $8 million.

Legal proceedings

Debt exchange litigation and purported notice of default—Prior to the consummation of the 2020 Exchange Transactions (see Note 9—Debt), we completed certain internal reorganization transactions (the “Internal Reorganization”).  In September 2020, funds managed by, or affiliated with, Whitebox Advisors LLC (“Whitebox”) as holders of certain series of our notes subject to the 2020 Exchange Offers, filed a claim (the “Claim”) in the U.S. District Court for the Southern District of New York (the “Trial Court”) related to such certain internal reorganization transactions and the 2020 Exchange Offers.  Additionally, in September and October 2020, Whitebox and funds managed by, or affiliated with, Pacific Investment Management Company LLC, as debtholders, together with certain other advisors and debtholders, provided purported notices of alleged default with respect to the indentures governing, respectively, the 8.00% Senior Notes and the 7.25% senior notes due November 2025 (the “7.25% Senior Notes”).

On September 23, 2020, we filed an answer to the Claim with the Trial Court and asserted counterclaims seeking a declaratory judgment that, among other matters, the Internal Reorganization did not cause a default under the indenture governing the 8.00% Senior Notes.  Concurrently, with our answer and counterclaims, we also submitted a motion for summary judgment seeking an expedited judgment on our request for declaratory judgment.  Whitebox subsequently submitted a cross-motion for summary judgment seeking dismissal of our counterclaims.  On November 30, 2020, while awaiting the Trial Court’s ruling on our motion for summary judgment, we amended certain of our financing documents and implemented certain internal reorganization transactions, which resolved the allegations contained in the purported notices of default.  On December 17, 2020, the Trial Court issued its ruling granting our motion for summary judgment and denying the plaintiff’s cross-motion for summary judgment, holding, among other matters, that the allegations contained in the purported notice of default did not constitute a default under the indenture governing the 8.00% Senior Notes.  Whitebox has appealed the Trial Court’s ruling.

The facts alleged in the purported notice of default under the 8.00% Senior Notes were the same as the facts underlying the Claim and the purported notice of default under the 7.25% Senior Notes.  Accordingly, following the amendment and internal reorganization transactions on November 30, 2020, and the subsequent ruling from the Trial Court granting our motion for summary judgment, we do not expect the liability, if any, resulting from these matters to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.  See Note 20—Subsequent Event.

Asbestos litigation—In 2004, several of our subsidiaries were named, along with numerous other unaffiliated defendants, in complaints filed in the Circuit Courts of the State of Mississippi, and in 2014, a group of similar complaints were filed in Louisiana.  The plaintiffs, former employees of some of the defendants, generally allege that the defendants used or manufactured asbestos containing drilling mud additives for use in connection with drilling operations, claiming negligence, products liability, strict liability and claims allowed under the Jones Act and general maritime law.  The plaintiffs generally seek awards of unspecified compensatory and punitive damages, but the court-appointed special master has ruled that a Jones Act employer defendant, such as us, cannot be sued for punitive damages.  One of our subsidiaries was named in additional complaints filed in Illinois and Missouri, where the plaintiffs similarly allege that the defendants manufactured asbestos containing products or used asbestos-containing drilling mud additives in connection with land-based drilling operations.  At December 31, 2021, 11 plaintiffs have claims pending in Louisiana and 9 plaintiffs have claims pending in Illinois and Missouri, in which we have or may have an interest.  We intend to defend these lawsuits vigorously, although we can provide no assurance as to the outcome.  We historically have maintained broad liability insurance, although we are not certain whether insurance will cover the liabilities, if any, arising out of these claims.  Based on our evaluation of the exposure to date, we do not expect the liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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One of our subsidiaries was named as a defendant, along with numerous other companies, in lawsuits arising out of the subsidiary’s manufacture and sale of heat exchangers, and involvement in the construction and refurbishment of major industrial complexes alleging bodily injury or personal injury as a result of exposure to asbestos.  As of December 31, 2021, the subsidiary was a defendant in approximately 250 lawsuits with a corresponding number of plaintiffs.  For many of these lawsuits, we have not been provided sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries.  The operating assets of the subsidiary were sold in 1989.  In December 2021, the subsidiary and certain insurers agreed to a settlement of outstanding disputes that provide the subsidiary with cash.  An earlier settlement, achieved in September 2018, provided the subsidiary with cash and an annuity that begins making payments in 2024.  Together with a coverage-in-place agreement with certain insurers and additional coverage issued by other insurers, we believe the subsidiary has sufficient resources to respond to both the current lawsuits as well as future lawsuits of a similar nature.  While we cannot predict or provide assurance as to the outcome of these matters, we do not expect the ultimate liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Macondo well incident—In June 2020, the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”) released the then-remaining $125 million of assets held in the escrow account established to satisfy our remaining obligations under the settlement agreement that we and the Plaintiff Steering Committee filed in May 2015 with the MDL Court, in which most claims against us for damages related to the blowout of the Macondo well in April 2010 were consolidated by the U.S. Judicial Panel on Multidistrict Litigation.  Following the release of assets, all significant litigation, including civil and criminal claims, resulting from the Macondo well incident had been resolved.

Other matters—We are involved in various regulatory matters and a number of claims and lawsuits, asserted and unasserted, all of which have arisen in the ordinary course of our business.  We do not expect the liability, if any, resulting from these other matters to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.  We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending, threatened, or possible litigation or liability.  We can provide no assurance that our beliefs or expectations as to the outcome or effect of any tax, regulatory, lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Environmental matters

We have certain potential liabilities under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state acts regulating cleanup of hazardous substances at various waste disposal sites, including those described below.  CERCLA is intended to expedite the remediation of hazardous substances without regard to fault.  Potentially responsible parties (“PRPs”) for each site include present and former owners and operators of, transporters to and generators of the substances at the site.  It is difficult to quantify the potential cost of environmental matters and remediation obligations.  Liability is strict and can be joint and several.

One of our subsidiaries was named as a PRP in connection with a site located in Santa Fe Springs, California, known as the Waste Disposal, Inc. site.  We and other PRPs agreed, under a participation agreement with the U.S. Environmental Protection Agency (the “EPA”) and the U.S. Department of Justice, to settle our potential liabilities by remediating the site.  The remedial action for the site was completed in 2006.  Our share of the ongoing operating and maintenance costs has been insignificant, and we do not expect any additional potential liabilities to be material.  Resolutions of other claims by the EPA, the involved state agency or PRPs are at various stages of investigation.  Nevertheless, based on available information with respect to all environmental matters, including all related pending legal proceedings, asserted legal claims and known potential legal claims that are likely to be asserted, we do not expect the ultimate liability, if any, resulting from such matters, to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Note 14—Equity

Share issuance—In June 2021, we commenced an at the market equity offering program (the “ATM Program”) with no expected expiration.  On June 14, 2021, we entered into an equity distribution agreement with a sales agent for the offer and sale of our shares, with up to a maximum aggregate net offering price of $400 million, under the ATM Program.  We intend to use the net proceeds from the ATM Program for general corporate purposes, which may include, among other things the repayment or refinancing of indebtedness and the funding of working capital, capital expenditures, investments and additional balance sheet liquidity.  In the year ended December 31, 2021, we received aggregate cash proceeds of $158 million, net of issue costs, for the aggregate sale of 36.1 million shares, under the ATM Program.

Shares held by subsidiaries—One of our subsidiaries holds our shares for future use to deliver shares in connection with sales under the ATM Program and in connection with awards granted under our incentive plans or other rights to acquire our shares.  At December 31, 2021 and 2020, our subsidiary held 72.7 million and 24.5 million shares, respectively.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Note 15—Share-Based Compensation

Overview

We have a long-term incentive plan (the “Long-Term Incentive Plan”) for executives, key employees and non-employee directors under which awards can be granted in the form of restricted share units, restricted shares, stock options, stock appreciation rights and cash performance awards.  Awards may be granted as service awards that are earned over a defined service period or as performance awards that are earned based on the achievement of certain market factors or performance targets or a combination of market factors and performance targets.  The compensation committee of our board of directors determines the terms and conditions of the awards granted under the Long-Term Incentive Plan.  At December 31, 2021, we had 85.7 million shares authorized and 30.0 million shares available to be granted under the Long-Term Incentive Plan.  At December 31, 2021, the total unrecognized compensation cost related to our unvested share-based awards was $29 million, which we expect to recognize over a weighted-average period of 1.8 years.

Service awards typically vest either in three equal annual installments beginning on the first anniversary date of the grant or in an aggregate installment at the end of the stated vesting period.  Service-based stock options, once fully vested, are typically exercisable during a seven-year period.  Performance awards typically vest in one aggregate installment following the ultimate determination date.  Performance awards are typically subject to a three-year measurement period during which the number of shares to be issued remains uncertain until the end of the performance period, at which time the awarded number of shares to be issued is determined.

Service awards

Restricted share units—A restricted share unit is a notional unit that is equal to one share but has no voting rights until the underlying share is issued.  The following table summarizes unvested activity during the year ended December 31, 2021 for service-based units granted under our incentive plan:

	Number	Weighted-average
	of	grant-date fair value
	units	per unit
Unvested at January 1, 2021	8,902,970	$	3.14
Granted	6,148,361		3.56
Vested	(4,368,749)		3.75
Forfeited	(19,717)		6.24
Unvested at December 31, 2021	10,662,865	$	3.13

In the year ended December 31, 2021, the vested service-based units had an aggregate grant-date fair value of $16 million.  During the years ended December 31, 2020 and 2019, we granted 7,093,421 and 3,044,494 service-based units, respectively, with a per unit weighted-average grant-date fair value of $1.41 and $8.33, respectively.  During the years ended December 31, 2020 and 2019, we had 2,817,155 and 2,224,030 service-based units, respectively, that vested with an aggregate grant-date fair value of $24 million and $23 million, respectively.

Stock options—The following table summarizes activity during the year ended December 31, 2021 for vested and unvested service-based stock options outstanding under our incentive plan:

				Weighted-average
	Number	Weighted-average		remaining	Aggregate
	of shares	exercise price		contractual term	intrinsic value
	under option	per share		(years)	(in millions)
Outstanding at January 1, 2021	4,385,147	$	12.31	6.62	$	—
Forfeited	(74,728)		19.21
Expired	(47,145)		78.76
Outstanding at December 31, 2021	4,263,274	$	11.45	5.70	$	—
Vested and exercisable at December 31, 2021	3,780,586	$	11.85	5.52	$	—

In the years ended December 31, 2021, 2020 and 2019, the vested stock options had an aggregate grant-date fair value of $9 million, $12 million and $10 million, respectively.  At December 31, 2021 and 2020, there were outstanding unvested stock options to purchase 482,688 and 1,355,448 shares, respectively.  During the year ended December 31, 2019, we granted stock options to purchase 1,594,528 shares with a per option weighted-average grant-date fair value of $8.35.

Performance awards

Restricted share units—We grant performance awards in the form of restricted share units that can be earned depending on the achievement of market factors and performance targets.  The number of shares ultimately earned per unit is quantified upon completion of

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

the specified period at the ultimate determination date.  The following table summarizes unvested activity during the year ended December 31, 2021 for performance-based units under our incentive plan:

	Number	Weighted-average
	of	grant-date fair value
	units	per unit
Unvested at January 1, 2021	3,560,884	$	4.40
Granted	3,025,512		3.70
Vested	(1,030,424)		10.77
Forfeited	(166,582)		10.79
Unvested at December 31, 2021	5,389,390	$	2.59

In each of the years ended December 31, 2021, 2020 and 2019, the vested performance-based units had an aggregate grant-date fair value of $11 million.  During the years ended December 31, 2020 and 2019, we granted 2,530,460 and 1,067,316 performance-based units, respectively, with a per unit weighted-average grant-date fair value of $1.80 and $10.77, respectively.

Note 16—Supplemental Balance Sheet Information

Other current liabilities were comprised of the following (in millions):

	December 31,
	2021		2020
Other current liabilities
Accrued employee benefits and payroll-related liabilities	$	178	$	224
Accrued interest		121		128
Accrued taxes, other than income		52		66
Finance lease liability		40		37
Operating lease liabilities		8		8
Deferred revenues		83		133
Contingent liabilities		60		60
Other		3		3
Total other current liabilities	$	545	$	659

Other long-term liabilities were comprised of the following (in millions):

	December 31,
	2021		2020
Other long-term liabilities
Postemployment benefit plan obligations	$	128	$	272
Finance lease liability		366		407
Operating lease liabilities		109		114
Income taxes payable		157		202
Deferred revenues		265		323
Other		43		48
Total other long-term liabilities	$	1,068	$	1,366

Note 17—Supplemental Cash Flow Information

The reconciling adjustments of our net cash provided by operating activities that were attributable to the net change in other operating assets and liabilities were as follows (in millions):

	Years ended December 31,
	2021		2020		2019
Changes in other operating assets and liabilities
Decrease in accounts receivable	$	137	$	67	$	87
Increase in other assets		(13)		(113)		(30)
Decrease in accounts payable and other current liabilities		(52)		(254)		(21)
Increase (decrease) in other long-term liabilities		(3)		2		(34)
Change in income taxes receivable / payable, net		(17)		(69)		(303)
Change in receivables from / payables to affiliates, net		(15)		14		(10)
	$	37	$	(353)	$	(311)

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Additional cash flow information was as follows (in millions):

		Years ended December 31,
		2021		2020		2019
Certain cash operating activities
Cash payments for interest		$	429	$	593	$	648
Cash payments for income taxes			57		70		121
Non-cash investing and financing activities
Capital additions, accrued at end of period	(a)	$	28	$	15	$	48
Issuance of debt in exchange transactions	(b)		294		925		—
Equity component of exchangeable debt	(c)		—		46		—

(a) Additions to property and equipment for which we had accrued a corresponding liability in accounts payable at the end of the period.  See Note 7—Long-Lived Assets.

(b) In the year ended December 31, 2021, in connection with the 2021 Private Exchange, we issued $294 million aggregate principal amount of the 4.00% Senior Guaranteed Exchangeable Bonds.  In the year ended December 31, 2020, in connection with the 2020 Exchange Transactions, we issued $687 million and $238 million aggregate principal amount of the 11.50% Senior Guaranteed Notes and the 2.50% Senior Guaranteed Exchangeable Bonds, respectively.  See Note 9—Debt.

(c) In connection with the issuance of the 2.50% Senior Guaranteed Exchangeable Bonds, we recorded the conversion feature, measured at its estimated fair value, to additional paid-in capital.  See Note 9—Debt.

Note 18—Financial Instruments

Overview—The carrying amounts and fair values of our financial instruments were as follows (in millions):

	December 31, 2021				December 31, 2020
	Carrying		Fair		Carrying		Fair
	amount		value		amount		value
Cash and cash equivalents	$	976	$	976	$	1,154	$	1,154
Restricted cash and cash equivalents		436		436		406		406
Long-term loans receivable from unconsolidated affiliates		36		33		2		2
Total debt		7,170		5,661		7,807		4,820

Cash and cash equivalents—Our cash and cash equivalents are primarily invested in demand deposits, short-term time deposits and money market funds.  The carrying amount of our cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of the instruments.

Restricted cash and cash equivalents—Our restricted cash and cash equivalents, which are subject to restrictions due to collateral requirements, legislation, regulation or court order, are primarily invested in demand deposits and money market funds.  The carrying amount of our restricted cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of the instruments.

Long-term loans receivable from unconsolidated affiliates—The carrying amount of our long-term loans receivable from unconsolidated affiliates, recorded in other assets, represents the principal amount of the cash investment.  We estimated the fair value of our long-term loans receivable from unconsolidated affiliates using significant unobservable inputs, representative of Level 3 fair value measurements, including the terms and credit spreads for the instruments.

Total debt—The carrying amount of our total debt represents the principal amount, contractual interest payments of previously restructured debt and unamortized discounts, premiums and issue costs.  The carrying amount and fair value of our total debt includes amounts related to certain exchangeable debt instruments (see Note 9—Debt).  We estimated the fair value of our total debt using significant other observable inputs, representative of Level 2 fair value measurements, including the terms and credit spreads for the instruments and, with respect to the exchangeable debt instruments, the expected volatility of the market price for our shares.

Note 19—Risk Concentration

Interest rate risk—We are exposed to the interest rate risk related to our fixed-rate debt when we refinance maturing debt with new debt or when we early retire debt in open market repurchases, exchanges or other market transactions.  We are also exposed to interest rate risk related to our restricted and unrestricted cash equivalents, as the interest income earned on these investments is based on variable or short-term interest rates, which change with market interest rates.

Currency exchange rate risk—We are exposed to currency exchange rate risk primarily related to employee compensation costs and purchasing costs that are denominated in currencies other than our functional currency, the U.S. dollar.  We use a variety of techniques to minimize the exposure to currency exchange rate risk, including the structuring of customer contract payment terms and occasional use of forward exchange contracts.  Our primary tool to manage currency exchange rate risk involves structuring customer contracts to provide

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

for payment in both U.S. dollars and local currency.  The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term.  Due to various factors, including customer acceptance, local banking laws, national content requirements, other statutory requirements, local currency convertibility, local inflation and revenue efficiency, actual local currency needs may vary from those realized in the customer contracts, resulting in partial exposure to currency exchange rate risk.  The currency exchange effect resulting from our international operations generally has not had a material impact on our operating results.

Credit risk—We are exposed to concentrations of credit risk primarily related to our restricted and unrestricted cash and cash equivalents and customer receivables, both current and long-term.  We generally maintain our restricted and unrestricted cash and cash equivalents in time deposits at commercial banks with high credit ratings or mutual funds, which invest exclusively in high-quality money market instruments, and we limit the amount of exposure to any one institution and do not believe we are exposed to any significant credit risk.  Regarding our customer receivables, which are dispersed in various countries, we earn our revenues by providing our drilling services to integrated energy companies, government-owned or government-controlled energy companies and other independent energy companies.  We establish an allowance for credit losses by applying an expected loss rate based on current and forecasted future and historical experience.  Although we have encountered only isolated credit concerns related to independent energy companies, we occasionally require collateral or other security to support customer receivables.  In certain instances, when we determine that collection is not reasonably assured, we may occasionally offer extended payment terms and recognize revenues associated with the contract on a cash basis.

Labor agreements—At December 31, 2021, we had a global workforce of approximately 5,530 individuals, including approximately 530 contractors.  Approximately 42 percent of our total workforce, working primarily in Norway, Brazil and the U.K., are represented by, and some of our contracted labor work is subject to, collective bargaining agreements, substantially all of which are subject to annual salary negotiation.  Negotiations over annual salary or other labor matters could result in higher personnel or other costs or increased operational restrictions or disruptions.  The outcome of any such negotiation generally affects the market for all offshore employees, not only union members.  A failure to reach an agreement on certain key issues could result in strikes, lockouts or other work stoppages.

Note 20—Subsequent Event

Debt exchange litigation and purported notice of default—On February 1, 2022, the U.S. Court of Appeals for the Second Circuit dismissed as moot the appeal filed by funds managed by, or affiliated with, Whitebox following the ruling by the Trial Court on December 17, 2020, which among other matters, granted our motion for summary judgment in connection with the previously disclosed lawsuit filed against us in September 2020 by Whitebox.

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

We have not had a change in or disagreement with our accountants within 24 months prior to the date of our most recent financial statements or in any period subsequent to such date.

Item 9A.Controls and Procedures

Disclosure controls and procedures—Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer, who is our principal executive officer, and our Chief Financial Officer, who is our principal financial officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms.  Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2021.

Internal control over financial reporting—There has been no change to our internal control over financial reporting during the quarter ended December 31, 2021 that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.  See “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” included in Item 8 of this annual report.

Item 9B.Other Information

None.

Item 9C.Disclosure Regarding Foreign Jurisdictions That Prevent Inspections

Not applicable.

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PART III

Item 10.Directors, Executive Officers and Corporate Governance

Item 11.Executive Compensation

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

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

Item 14.Principal Accountant Fees and Services

The information required by Items 10, 11, 12, 13 and 14 is incorporated herein by reference to our definitive proxy statement for our 2022 annual general meeting of shareholders, which will be filed with the U.S. Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2021.  Certain information with respect to our executive officers is set forth at the end of Part I of this annual report under the caption “Information About our Executive Officers.”

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PART IV

Item 15.Exhibits and Financial Statement Schedules

(a)Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Index to Financial Statements

Included in Part II of this report:	Page
Management’s Report on Internal Control Over Financial Reporting	41
Reports of Independent Registered Public Accounting Firm (PCAOB ID 00042)	42
Consolidated Statements of Operations	45
Consolidated Statements of Comprehensive Loss	46
Consolidated Balance Sheets	47
Consolidated Statements of Equity	48
Consolidated Statements of Cash Flows	49
Notes to Consolidated Financial Statements	50

Financial statements of unconsolidated subsidiaries are not presented herein because such subsidiaries do not meet the significance test.

(2) Financial Statement Schedules

Transocean Ltd. and Subsidiaries

Schedule II - Valuation and Qualifying Accounts

(In millions)

			Additions
					Charge to
	Balance at		Charge to cost		other						Balance at
	beginning of		and		accounts			Deductions			end of
	period		expenses		-describe			-describe			period
Year ended December 31, 2019
Reserves and allowances deducted from asset accounts:
Allowance for excess materials and supplies	$	134		3		—			10	(a)	$	127
Valuation allowance on deferred tax assets		681		37		—			2	(b)		716
Year ended December 31, 2020
Reserves and allowances deducted from asset accounts:
Allowance for credit losses	$	—		—		2	(c)		—		$	2
Allowance for excess materials and supplies		127		25		—			9	(a)		143
Valuation allowance on deferred tax assets		716		(31)		—			—			685
Year ended December 31, 2021
Reserves and allowances deducted from asset accounts:
Allowance for credit losses	$	2		—		—			—		$	2
Allowance for excess materials and supplies		143		43		—			3	(a)		183
Valuation allowance on deferred tax assets		685		1,167		—			32	(b)		1,820

(a) Amount related to materials and supplies on rigs and related assets sold or classified as held for sale.

(b) Amount related to adjustments to other deferred tax assets with valuation allowances.

(c) Amount related to an adjustment to the allowance for credit losses with a corresponding entry to accumulated deficit associated with our adoption of the accounting standards update that requires an entity to estimate an expected lifetime credit loss on financial assets ranging from short-term trade accounts receivable to long-term financings without retrospective application.

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(3) Exhibits

The following exhibits are filed or furnished herewith, as indicated, or incorporated by reference to the location indicated:

Number		Description	Location
	1.1	Equity Distribution Agreement, dated as of June 14, 2021, by and between Transocean Ltd. and Jefferies LLC	Exhibit 1.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on June 15, 2021
	2.1	Agreement and Plan of Merger, dated September 3, 2018, by and among Transocean Ltd., Transocean Oceanus Holdings Limited, Transocean Oceanus Limited and Ocean Rig UDW Inc.	Exhibit 2.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on September 4, 2018
	3.1	Articles of Association of Transocean Ltd.	Exhibit 3.1 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended September 30, 2021 filed on November 2, 2021
	3.2	Organizational Regulations of Transocean Ltd., amended, effective as of April 7, 2021	Exhibit 3.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on April 7, 2021
	4.1	Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934	Filed herewith
	4.2	Indenture dated as of February 26, 2021 by and among Transocean Inc., the guarantors and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on February 26, 2021
	4.3	Credit Agreement dated June 22, 2018, among Transocean Inc., the lenders parties thereto and Citibank, N.A., as administrative agent and collateral agent.	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on June 27, 2018
	4.4	Increase of Commitments and First Amendment to Credit Agreement, dated May 13, 2019, among Transocean Inc., the lenders and issuing banks parties thereto, Citibank, N.A., as administrative agent, and for the limited purposes set forth therein, Transocean Ltd. and certain of its subsidiaries	Exhibit 10.1 to Transocean Ltd.’ s Current Report on Form 8-K (Commission File No. 001-38373) filed on May 13, 2019
	4.5	Increase of Commitments, Second Amendment to Credit Agreement and First Amendment to Guaranties, dated July 15, 2019, among Transocean Inc., the lenders and issuing banks parties thereto, Citibank, N.A., as administrative agent, and for the limited purposes set forth therein, Transocean Ltd. and certain of its subsidiaries	Exhibit 10.1 to Transocean Ltd.’ s Current Report on Form 8-K (Commission File No. 001-38373) filed on July 15, 2019
	4.6	Curative Agreement, dated September 24, 2019, between Transocean Inc. and Citibank, N.A., as administrative agent for the lenders under the Credit Agreement dated June 22, 2018, as amended	Exhibit 10.2 to Transocean Ltd.’ s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended September 30, 2019
	4.7	Increase of Commitments and Third Amendment to Credit Agreement, dated December 23, 2019, among Transocean Inc., the lenders and issuing banks parties thereto, Citibank, N.A., as administrative agent, and for the limited purposes set forth therein, Transocean Ltd. and certain of its subsidiaries	Exhibit 4.6 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 001-38373) filed on February 18, 2020
	4.8	Indenture, dated July 13, 2018, by and among Transocean Guardian Limited, the Guarantors and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on July 17, 2018
	4.9	Indenture, dated July 20, 2018, by and among Transocean Pontus Limited, the Guarantors and Wells Fargo Bank, National Association.	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on July 24, 2018
	4.10	First Supplemental Indenture, dated April 15, 2019, by and among Transocean Pontus Limited, Wells Fargo Bank, National Association, as trustee and collateral agent, and the Note Parties, supplementing the Indenture dated as of July 20, 2018	Exhibit 4.4 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended March 31, 2019
	4.11	Indenture dated as of April 15, 1997 between Transocean Offshore Inc. and Texas Commerce Bank National Association, as trustee	Exhibit 4.1 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997
	4.12	First Supplemental Indenture dated as of April 15, 1997 between Transocean Offshore Inc. and Texas Commerce Bank National Association, as trustee, supplementing the Indenture dated as of April 15, 1997	Exhibit 4.2 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997
	4.13	Second Supplemental Indenture dated as of May 14, 1999 between Transocean Offshore (Texas) Inc., Transocean Offshore Inc. and Chase Bank of Texas, National Association, as trustee	Exhibit 4.5 to Transocean Offshore Inc.’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-59001-99) filed on June 29, 1999
	4.14	Fifth Supplemental Indenture, dated as of December 18, 2008, among Transocean Ltd., Transocean Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee	Exhibit 4.4 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 19, 2008

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Number		Description	Location
	4.15	Form of 7.45% Notes due April 15, 2027	Exhibit 4.3 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997
	4.16	Form of 8.00% Debentures due April 15, 2027	Exhibit 4.4 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997
	4.17	Officers’ Certificate establishing the terms of the 7.50% Notes due April 15, 2031	Exhibit 4.3 to Transocean Sedco Forex Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on April 9, 2001
	4.18	Officers’ Certificate establishing the terms of the 7.375% Notes due April 15, 2018	Exhibit 4.14 to Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the fiscal year ended December 31, 2001
	4.19	Indenture dated as of September 1, 1997, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc.	Exhibit 4.1 of Global Marine Inc.’s Registration Statement on Form S-4 (No. 333-39033) filed on October 30, 1997
	4.20	First Supplemental Indenture dated as of June 23, 2000, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc.	Exhibit 4.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 001-05471) for the quarter ended June 30, 2000
	4.21	Second Supplemental Indenture dated as of November 20, 2001, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc.	Exhibit 4.2 to GlobalSantaFe Corporation’s Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2004
	4.22	Third Supplemental Indenture, dated as of July 29, 2019, among Global Marine Inc, Transocean Inc. and Wilmington Trust Company, as trustee, relating to Debt Securities of Global Marine Inc.	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on July 29, 2019
	4.23	Form of 7% Note Due 2028	Exhibit 4.2 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 001-05471) filed on May 22, 1998
	4.24	Terms of 7% Notes Due 2028	Exhibit 4.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 001-05471) filed on May 22, 1998
	4.25	Indenture, dated as of December 11, 2007, between Transocean Inc. and Wells Fargo Bank, National Association	Exhibit 4.36 to Transocean Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2007
	4.26	First Supplemental Indenture, dated as of December 11, 2007, between Transocean Inc. and Wells Fargo Bank, National Association	Exhibit 4.37 to Transocean Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2007
	4.27	Third Supplemental Indenture, dated as of December 18, 2008, among Transocean Ltd., Transocean Inc. and Wells Fargo Bank, National Association, as trustee	Exhibit 4.3 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 19, 2008
	4.28	Fourth Supplemental Indenture, dated as of September 21, 2010, among Transocean Ltd., Transocean Inc. and Wells Fargo Bank, National Association, as trustee	Exhibit 4.1 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended September 30, 2010
	4.29	Fifth Supplemental Indenture, dated as of December 5, 2011, among Transocean Ltd., Transocean Inc. and Wells Fargo Bank, National Association, as trustee	Exhibit 4.3 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on December 5, 2011
	4.30	Sixth Supplemental Indenture, dated as of September 13, 2012, among Transocean Inc., Transocean Ltd. and Wells Fargo Bank, National Association, as trustee	Exhibit 4.3 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on September 13, 2012
	4.31	Indenture, dated as of July 21, 2016, by and among Transocean Inc., the Guarantors and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on July 22, 2016
	4.32	Indenture, dated as of October 19, 2016, by and among Transocean Phoenix 2 Limited, Transocean Ltd., Transocean Inc., Triton Capital II GmbH and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on October 20, 2016
	4.33	First Supplemental Indenture, dated April 15, 2019, by and among Transocean Phoenix 2 Limited, Wells Fargo Bank, National Association, as trustee and collateral agent, and the Note Parties supplementing the Indenture dated as of October 19, 2016	Exhibit 4.2 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended March 31, 2019
	4.34	Indenture, dated December 8, 2016, by and among Transocean Proteus Limited, the Guarantors and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on December 8, 2016

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Number		Description	Location
	4.35	First Supplemental Indenture, dated April 15, 2019, by and among Transocean Proteus Limited, Wells Fargo Bank, National Association, as trustee and collateral agent, and the Note Parties, supplementing the Indenture dated as of December 8, 2016	Exhibit 4.3 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended March 31, 2019
	4.36	Indenture dated as of October 17, 2017, by and among Transocean Inc., the guarantors party thereto and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on October 17, 2017
	4.37	Indenture, dated January 30, 2018, among Transocean Inc., Transocean Ltd., as guarantor, and Computershare Trust Company N.A. and Computershare Trust Company of Canada, as co-trustees	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on January 30, 2018
	4.38	Form of 0.50% Exchangeable Senior Bonds due 2023	Exhibit A of Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on January 30, 2018
	4.39	Registration Rights Agreement, dated as of January 30, 2018, among Transocean Ltd., Transocean Inc., and the security holders named therein	Exhibit 4.3 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on January 30, 2018
	4.40	Indenture, dated October 25, 2018, among Transocean Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee	Exhibit 4.32 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 001-38373) filed on February 19, 2019
	4.41	Indenture, dated February 1, 2019, by and among Transocean Poseidon Limited, the Guarantors and Wells Fargo Bank, National Association, as trustee and collateral agent	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on February 1, 2019
	4.42	Indenture, dated May 24, 2019, by and among Transocean Sentry Limited, the Guarantors and Wells Fargo Bank, National Association, as trustee and collateral agent	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on May 29, 2019
	4.43	Indenture, dated January 17, 2020, by and among Transocean Inc., the guarantors party thereto and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on January 17, 2020
	4.44	Indenture, dated as of August 14, 2020, by and among Transocean Inc., the guarantors party thereto and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on August 14, 2020
	4.45	Amendment to Registration Rights Agreement, dated as of August 14, 2020, by and among Transocean Ltd., Transocean Inc. and Perestroika (Cyprus) Ltd.	Exhibit 4.2 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on August 14, 2020
	4.46	Indenture, dated as of September 11, 2020, by and among Transocean Inc., the guarantors party thereto and Wells Fargo Bank, National Association	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on September 11, 2020
	4.47	Supplemental Indenture, dated November 30, 2020, by and among Transocean Inc., Transocean Ltd., certain of Transocean Inc.’s subsidiaries, and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture dated as of September 11, 2020.	Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on December 1, 2020
	4.48	Supplemental Indenture, dated November 30, 2020, by and among Transocean Inc., Transocean Ltd., certain of Transocean Inc.’s subsidiaries, and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture dated as of August 14, 2020.	Exhibit 4.2 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on December 1, 2020
	4.49	Fourth Amendment to Credit Agreement, dated November 30, 2020, among Transocean Inc., the lenders and issuing banks parties thereto, Citibank, N.A., as administrative agent, and for the limited purposes set forth therein, certain of Transocean Inc.’s subsidiaries.	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on December 1, 2020.
*	10.1	Amended and Restated 2015 Transocean Ltd. Long-Term Incentive Plan	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on June 1, 2021
	10.2	Shipyard Credit Agreement for Deepwater Atlas, dated as of June 5, 2021, by and between Jurong Shipyard Pte. Ltd. and Transocean Offshore Deepwater Holdings Limited	Exhibit 10.2 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended June 30, 2021 filed on August 3, 2021
	10.3	Shipyard Credit Agreement for Deepwater Titan, dated as of June 5, 2021, by and between Jurong Shipyard Pte. Ltd. and Transocean Offshore Deepwater Holdings Limited	Exhibit 10.3 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended June 30, 2021 filed on August 3, 2021
	10.4	Form of Voting and Support Agreement, by and among Transocean Ltd. and certain shareholders of Ocean Rig UDW Inc.	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on September 4, 2018
	10.5	Form of Voting and Support Agreement, by and among Ocean Rig UDW Inc. and certain shareholders of Transocean Ltd.	Exhibit 10.2 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on September 4, 2018.
*	10.6	Long-Term Incentive Plan of Transocean Ltd. (as amended and restated as of February 12, 2009)	Exhibit 10.5 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008

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Number		Description	Location
*	10.7	First Amendment to Long-Term Incentive Plan of Transocean Ltd. (as amended and restated as of February 12, 2009)	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on May 22, 2013
*	10.8	Deferred Compensation Plan of Transocean Offshore Inc., as amended and restated effective January 1, 2000	Exhibit 10.10 to Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 1999
*	10.9	GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective January 1, 2001 and Amendment to GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective November 20, 2001	Exhibit 10.33 to the GlobalSantaFe Corporation Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2004
*	10.10	Amendment to Transocean Inc. Deferred Compensation Plan	Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 29, 2005
*	10.11	Form of 2004 Performance-Based Nonqualified Share Option Award Letter	Exhibit 10.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on February 15, 2005
*	10.12	Form of 2004 Director Deferred Unit Award	Exhibit 10.4 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on February 15, 2005
*	10.13	Form of 2008 Director Deferred Unit Award	Exhibit 10.20 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008
*	10.14	Form of 2009 Director Deferred Unit Award	Exhibit 10.19 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2009
*	10.15	Terms and Conditions of 2013 Director Deferred Unit Award	Exhibit 10.14 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
*	10.16	Terms and Conditions of 2014 Director Deferred Unit Award	Exhibit 10.15 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
*	10.17	Terms and Conditions of 2015 Director Restricted Share Unit Award	Exhibit 10.16 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
*	10.18	Terms and Conditions of 2014 Executive Equity Award	Exhibit 10.19 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
*	10.19	Terms and Conditions of 2015 Executive Equity Award	Exhibit 10.20 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
	10.20	Terms and Conditions of the July 2008 Nonqualified Share Option Award	Exhibit 10.2 to Transocean Inc.’s Annual Report on Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2008
*	10.21	Terms and Conditions of the February 2009 Nonqualified Share Option Award	Exhibit 10.30 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008
*	10.22	Terms and Conditions of the February 2012 Long Term Incentive Plan Award	Exhibit 10.28 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2011
*	10.23	Transocean Ltd. Incentive Recoupment Policy	Exhibit 10.30 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2012
	10.24	Form of Novation Agreement dated as of November 27, 2007 by and among GlobalSantaFe Corporation, Transocean Offshore Deepwater Drilling Inc. and certain executives	Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007
*	10.25	Global Marine Inc. 1990 Non-Employee Director Stock Option Plan	Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 001-05471) for the year ended December 31, 1991
*	10.26	First Amendment to Global Marine Inc. 1990 Non-Employee Director Stock Option Plan	Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 001-05471) for the quarter ended June 30, 1995

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Number		Description	Location
*	10.27	Second Amendment to Global Marine Inc. 1990 Non-Employee Director Stock Option Plan	Exhibit 10.37 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 001-05471) for the year ended December 31, 1996
*	10.28	1997 Long-Term Incentive Plan	GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997
*	10.29	Amendment to 1997 Long Term Incentive Compensation Plan	Exhibit 10.25 of GlobalSantaFe Corporation’s Annual Report on Form 20-F (Commission File No. 001-14634) for the year ended December 31, 1998
*	10.30	Amendment to 1997 Long Term Incentive Plan, dated December 1, 1999	Exhibit 10.33 of GlobalSantaFe Corporation’s Annual Report on Form 20-F (Commission File No. 001-14634) for the year ended December 31, 1999
*	10.31	GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan	Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 001-05471) for the quarter ended March 31, 1998
*	10.32	First Amendment to GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan	Exhibit 10.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 001-05471) for the quarter ended June 30, 2000
*	10.33	GlobalSantaFe Corporation 2001 Non-Employee Director Stock Option and Incentive Plan	Exhibit 4.8 of GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-73878) filed on November 21, 2001
*	10.34	GlobalSantaFe Corporation 2001 Long-Term Incentive Plan	Exhibit A to GlobalSantaFe Corporation’s definitive proxy statement (Commission File No. 001-14634) filed on March 21, 2001
*	10.35	GlobalSantaFe 2003 Long-Term Incentive Plan (as Amended and Restated Effective June 7, 2005)	Exhibit 10.4 to GlobalSantaFe Corporation’s Quarterly Report on Form 10-Q (Commission File No. 001-14634) for the quarter ended June 30, 2005
*	10.36	Transocean Ltd. Pension Equalization Plan, as amended and restated, effective January 1, 2009	Exhibit 10.41 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008
*	10.37	Transocean U.S. Supplemental Retirement Benefit Plan, as amended and restated, effective as of November 27, 2007	Exhibit 10.11 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007
*	10.38	GlobalSantaFe Corporation Supplemental Executive Retirement Plan	Exhibit 10.1 to the GlobalSantaFe Corporation Quarterly Report on Form 10-Q (Commission File No. 001-14634) for the quarter ended September 30, 2002
*	10.39	Transocean U.S. Supplemental Savings Plan, as amended and restated, effective as of January 1, 2009	Exhibit 10.44 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008
	10.40	Form of Indemnification Agreement entered into between Transocean Ltd. and each of its Directors and Executive Officers	Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on October 10, 2008
*	10.41	Form of Assignment Memorandum for Executive Officers	Exhibit 10.6 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on December 19, 2008
	10.42	Drilling Contract between Vastar Resources, Inc. and R&B Falcon Drilling Co. dated December 9, 1998 with respect to Deepwater Horizon, as amended	Exhibit 10.1 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarterly period ended June 30, 2010
*	10.43	Executive Severance Benefit Policy	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on February 23, 2012
	10.44	Term Sheet Agreement for a Transocean and PSC/DHEPDS Settlement, dated May 20, 2015, among Triton Asset Leasing GmbH, Transocean Deepwater Inc., Transocean Offshore Deepwater Drilling Inc., Transocean Holdings LLC, the Plaintiffs Steering Committee in MDL 2179, and the Deepwater Horizon Economic and Property Damages Settlement Class	Exhibit 10.3 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended June 30, 2015
	10.45	Confidential Settlement Agreement, Mutual Releases and Agreement to Indemnify, dated May 20, 2015, among Transocean Offshore Deepwater Drilling Inc., Transocean Deepwater Inc., Transocean Holdings LLC, Triton Asset Leasing GmbH, BP Exploration and Production Inc. and BP America Production Co.	Exhibit 10.6 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended June 30, 2015

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Number		Description	Location
	10.46	Transocean Punitive Damages and Assigned Claims Settlement Agreement, dated May 29, 2015, among Transocean Offshore Deepwater Drilling Inc., Transocean Deepwater Inc., Transocean Holdings LLC, Triton Asset Leasing GmbH, the Plaintiffs Steering Committee in MDL 2179, and the Deepwater Horizon Economic and Property Damages Settlement Class	Exhibit 10.7 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended June 30, 2015
*	10.47	Employment Agreement with Jeremy D. Thigpen effective September 1, 2016	Exhibit 10.1 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended September 30, 2016
*	10.48	Employment Agreement with Mark L. Mey effective September 1, 2016	Exhibit 10.2 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended September 30, 2016
*	10.49	Amended and Restated Performance Award and Cash Bonus Plan of Transocean Ltd.	Exhibit 10.48 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 001-38373) for the year ended December 31, 2020
*	10.50	Terms and Conditions of 2020 Executive Equity Awards	Exhibit 10.2 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended June 30, 2020
*	10.51	Terms and Conditions of 2020 Director Restricted Share Unit Award	Exhibit 10.3 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 001-38373) for the quarter ended June 30, 2020
*	10.52	Terms and Conditions of 2022 Executive Equity Awards	Filed Herewith
*	10.53	Employment Agreement with Keelan Adamson effective February 16, 2022	Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on February 17, 2022
	21	Subsidiaries of Transocean Ltd.	Filed herewith
	23.1	Consent of Ernst & Young LLP	Filed herewith
	24	Powers of Attorney	Filed herewith
	31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
	31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
	32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
	32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith
	101	Interactive data files pursuant to Rule 405 of Regulation S-T formatted in Inline Extensible Business Reporting Language: (i) our consolidated balance sheets as of December 31, 2021 and December 31, 2020; (ii) our consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019; (iii) our consolidated statements of comprehensive loss for the years ended December 31, 2021, 2020 and 2019; (iv) our consolidated statements of equity for the years ended December 31, 2021, 2020 and 2019; (v) our consolidated statements of cash flows for the years ended December 31, 2021, 2020 and 2019; and (vi) the notes to consolidated financial statements	Filed herewith
	104	The cover page from our annual report on Form 10-K for the year ended December 31, 2021, formatted in Inline Extensible Business Reporting Language	Filed herewith

* Compensatory plan or arrangement

Exhibits listed above as previously having been filed with the U.S. Securities and Exchange Commission are incorporated herein by reference pursuant to Rule 12b-32 under the Securities Exchange Act of 1934 and made a part hereof with the same effect as if filed herewith.

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Certain instruments relating to our long-term debt and our subsidiaries have not been filed as exhibits since the total amount of securities authorized under any such instrument does not exceed 10 percent of our total assets and our subsidiaries on a consolidated basis.  We agree to furnish a copy of each such instrument to the SEC upon request.

Certain agreements filed as exhibits to this Report may contain representations and warranties by the parties to such agreements.  These representations and warranties have been made solely for the benefit of the parties to such agreements and (1) may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (2) may have been qualified by certain disclosures that were made to other parties in connection with the negotiation of such agreements, which disclosures are not reflected in such agreements, and (3) may apply standards of materiality in a way that is different from what may be viewed as material to investors.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on February 23, 2022.

TRANSOCEAN LTD.
By:	/s/ Mark L. Mey
	Mark L. Mey
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By:	/s/ David Tonnel
	David Tonnel
	Senior Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on February 23, 2022.

Signature	Title
*	Chairman of the Board of Directors
Chadwick C. Deaton
/s/ Jeremy D. Thigpen	Chief Executive Officer
Jeremy D. Thigpen	(Principal Executive Officer)
/s/ Mark L. Mey	Executive Vice President and Chief Financial Officer
Mark L. Mey	(Principal Financial Officer)
/s/ David Tonnel	Senior Vice President and Chief Accounting Officer
David Tonnel	(Principal Accounting Officer)
*	Director
Glyn A. Barker
*	Director
Vanessa C.L. Chang
*	Director
Frederico F. Curado
*	Director
Vincent J. Intrieri
*	Director
Samuel J. Merksamer
*	Director
Frederik W. Mohn
*	Director
Edward R. Muller
*	Director
Margareth Øvrum
*	Director
Diane de Saint Victor
By: /s/ David Tonnel
(Attorney-in-Fact)

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