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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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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, 2019

OR

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

For the transition period from _____ to _____

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Commission file number 001-38373

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TRANSOCEAN LTD.

(Exact name of registrant as specified in its charter)

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​ | ​
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)

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

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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

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

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

As of June 30, 2019, 611,741,184 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $3.9 billion (based on the reported closing market price of the shares of Transocean Ltd. on June 30, 2019 of $6.41 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 12, 2020, 612,573,158 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, 2019, for its 2020 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

Table of Contents

TRANSOCEAN LTD. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2019

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Item | ​ | Page
​ | ​ | ​
PART I
Item 1. | Business | 2
Item 1A. | Risk Factors | 8
Item 1B. | Unresolved Staff Comments | 21
Item 2. | Properties | 21
Item 3. | Legal Proceedings | 21
Item 4. | Mine Safety Disclosures | 21
​ | ​ | ​
PART II
Item 5. | Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities | 23
Item 6. | Selected Financial Data | 25
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 26
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 40
Item 8. | Financial Statements and Supplementary Data | 41
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 80
Item 9A. | Controls and Procedures | 80
Item 9B. | Other Information | 80
​ | ​ | ​
PART III
Item 10. | Directors, Executive Officers and Corporate Governance | 81
Item 11. | Executive Compensation | 81
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters | 81
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 81
Item 14. | Principal Accounting Fees and Services | 81
​ | ​ | ​
PART IV
Item 15. | Exhibits and Financial Statement Schedules | 82

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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:

◾our results of operations, our revenue efficiency and other performance indicators and our cash flow from operations;
◾the offshore drilling market, including the effects of declines 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 the various geographies in which we operate or our classes of rigs;
◾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;
◾liquidity, including availability under our bank credit agreement, and adequacy of cash flows for our obligations;
◾debt levels, including impacts of a financial and economic downturn, and interest rates;
◾newbuild, upgrade, shipyard and other capital projects, including completion, relinquishment or abandonment, delivery and commencement of operation dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects;
◾the cost and timing of acquisitions and the proceeds and timing of dispositions;
◾the optimization of rig-based spending;
◾tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Brazil, Norway, the United Kingdom (“U.K.”) and the U.S.;
◾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, defined benefit pension plan contributions, the timing of 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 adequacy of and access to our sources of liquidity;
◾our inability to obtain drilling contracts for our rigs that do not have contracts;
◾our inability to renew drilling contracts at comparable dayrates;
◾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.

Table of Contents

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 12, 2020, we owned or had partial ownership interests in and operated a fleet of 45 mobile offshore drilling units, consisting of 28 ultra-deepwater floaters, 14 harsh environment floaters and three midwater floaters. As of February 12, 2020, we were constructing two ultra-deepwater drillships.

Our primary business is to contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis 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 mobile offshore drilling fleet is one of the most versatile fleets in the world, consisting of drillship 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 Zug, Switzerland. Our telephone number at that address is +41 41 749-0500. Our shares are listed on the New York Stock Exchange under the 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 22—Operating Segments, Geographic Analysis and Major Customers.”

Drilling Fleet

Overview—Our drilling fleet of floaters consists of drillships and semisubmersibles, which are mobile and can be moved to new locations in response to customer demand. Our drilling equipment is suitable for both exploration and development, and we engage in both types of drilling activity. Our mobile offshore drilling units 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.

Drillships are generally self-propelled vessels, shaped like conventional ships, and are the most mobile of the major rig types. 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. Ultra-deepwater drillships typically have greater deck load and storage capacity than early generation 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. 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 drillship under construction will be equipped with and our uncontracted newbuild drillship will be equipped to accommodate two 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. Five of our 21 semisubmersibles are equipped with dual-activity technology and also have mooring capability. Two of these five 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.

Fleet categories—We further categorize the drilling units of our fleet as follows: (1) “ultra-deepwater floaters,” (2) “harsh environment floaters” and (3) “midwater floaters”. 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. Midwater floaters are generally comprised of those non-high-specification semisubmersibles that have a water depth capacity of less than 4,500 feet.

Fleet status—Depending on market conditions, we may idle or stack 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

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Table of Contents

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 over time, depends upon various factors, including the availability and cost of shipyard facilities, the cost of equipment and materials and the extent of repairs and maintenance that may ultimately be required. 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, 2020, 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, 2020, 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.

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Water | ​ | Drilling | ​ | Contracted | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | depth | ​ | depth | ​ | location or | ​
​ | ​ | ​ | ​ | ​ | ​ | Expected | ​ | capacity | ​ | capacity | ​ | contracted | ​
Rig category and name |  | Specifications |  | Type |  | completion |  | (in feet) |  | (in feet) |  | status |
Rigs under construction (2) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deepwater Atlas | ​ | (a) (b) (c) (d) | ​ | Drillship | ​ | — | ​ | 12,000 | ​ | 40,000 | ​ | Uncontracted | ​
Deepwater Titan | ​ | (a) (b) (c) (e) | ​ | Drillship | ​ | 4Q 2021 | ​ | 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 two blowout preventers.

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

(e) | To be equipped with two 20,000 pounds psi blowout preventers.

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Table of Contents

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Water | ​ | Drilling | ​ | Contracted | ​
​ | ​ | ​ | ​ | ​ | ​ | Year | ​ | depth | ​ | depth | ​ | location or | ​
​ | ​ | ​ | ​ | ​ | ​ | entered | ​ | capacity | ​ | capacity | ​ | standby | ​
Rig category and name |  | Specifications |  | Type |  | service |  | (in feet) |  | (in feet) |  | status |
Ultra-deepwater floaters (28) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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) | ​ | 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) (e) | ​ | Drillship | ​ | 2010 | ​ | 12,000 | ​ | 40,000 | ​ | Egypt | ​
Discoverer Luanda | ​ | (a) (b) (e) | ​ | Drillship | ​ | 2010 | ​ | 7,500 | ​ | 40,000 | ​ | Stacked | ​
Dhirubhai Deepwater KG2 | ​ | (a) | ​ | Drillship | ​ | 2010 | ​ | 12,000 | ​ | 35,000 | ​ | Australia | ​
Discoverer Inspiration | ​ | (a) (b) (c) (e) | ​ | Drillship | ​ | 2010 | ​ | 12,000 | ​ | 40,000 | ​ | U.S. Gulf | ​
Discoverer Americas | ​ | (a) (b) (e) | ​ | Drillship | ​ | 2009 | ​ | 12,000 | ​ | 40,000 | ​ | Stacked | ​
Development Driller III | ​ | (a) (b) (f) | ​ | Semisubmersible | ​ | 2009 | ​ | 7,500 | ​ | 37,500 | ​ | Equatorial Guinea | ​
Petrobras 10000 | ​ | (a) (b) | ​ | Drillship | ​ | 2009 | ​ | 12,000 | ​ | 37,500 | ​ | Brazil | ​
Discoverer Clear Leader | ​ | (a) (b) (c) (e) | ​ | Drillship | ​ | 2009 | ​ | 12,000 | ​ | 40,000 | ​ | Stacked | ​
Dhirubhai Deepwater KG1 | ​ | (a) | ​ | Drillship | ​ | 2009 | ​ | 12,000 | ​ | 35,000 | ​ | India | ​
GSF Development Driller II | ​ | (a) (b) (f) | ​ | Semisubmersible | ​ | 2005 | ​ | 7,500 | ​ | 37,500 | ​ | Stacked | ​
GSF Development Driller I | ​ | (a) (b) (f) | ​ | Semisubmersible | ​ | 2005 | ​ | 7,500 | ​ | 37,500 | ​ | Australia | ​
Deepwater Nautilus | ​ | (f) | ​ | Semisubmersible | ​ | 2000 | ​ | 8,000 | ​ | 30,000 | ​ | Brunei | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Harsh environment floaters (14) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Transocean Norge | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2019 | ​ | 10,000 | ​ | 40,000 | ​ | Norwegian N. Sea | ​
Transocean Enabler | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2016 | ​ | 1,640 | ​ | 28,000 | ​ | Norwegian N. Sea | ​
Transocean Encourage | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2016 | ​ | 1,640 | ​ | 28,000 | ​ | Norwegian N. Sea | ​
Transocean Endurance | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2015 | ​ | 1,640 | ​ | 28,000 | ​ | Norwegian N. Sea | ​
Transocean Equinox | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2015 | ​ | 1,640 | ​ | 28,000 | ​ | Norwegian N. Sea | ​
Polar Pioneer | ​ | (f) | ​ | Semisubmersible | ​ | 1985/2014 | ​ | 1,500 | ​ | 25,000 | ​ | Stacked | ​
Songa Dee | ​ | (f) | ​ | Semisubmersible | ​ | 1984/2014 | ​ | 1,500 | ​ | 30,000 | ​ | Stacked | ​
Transocean Spitsbergen | ​ | (a) (f) (g) | ​ | Semisubmersible | ​ | 2010 | ​ | 10,000 | ​ | 30,000 | ​ | Norwegian N. Sea | ​
Transocean Barents | ​ | (a) (f) (g) | ​ | Semisubmersible | ​ | 2009 | ​ | 10,000 | ​ | 30,000 | ​ | Canada | ​
Henry Goodrich | ​ | (f) | ​ | Semisubmersible | ​ | 1985/2007 | ​ | 5,000 | ​ | 30,000 | ​ | Idle | ​
Leiv Eiriksson | ​ | (a) (f) | ​ | Semisubmersible | ​ | 2001 | ​ | 7,500 | ​ | 25,000 | ​ | Norwegian N. Sea | ​
Transocean Leader | ​ | (f) | ​ | Semisubmersible | ​ | 1987/1997 | ​ | 4,500 | ​ | 25,000 | ​ | U.K. N. Sea | ​
Paul B. Loyd, Jr. | ​ | (f) | ​ | Semisubmersible | ​ | 1990 | ​ | 2,000 | ​ | 25,000 | ​ | U.K. N. Sea | ​
Transocean Arctic | ​ | (f) | ​ | Semisubmersible | ​ | 1986 | ​ | 1,650 | ​ | 25,000 | ​ | Norwegian N. Sea | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Midwater floaters (3) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Sedco 714 | ​ | (f) | ​ | Semisubmersible | ​ | 1983/1997 | ​ | 1,600 | ​ | 25,000 | ​ | Stacked | ​
Transocean 712 | ​ | (f) | ​ | Semisubmersible | ​ | 1983 | ​ | 1,600 | ​ | 25,000 | ​ | U.K. N. Sea | ​
Sedco 711 | ​ | (f) | ​ | Semisubmersible | ​ | 1982 | ​ | 1,800 | ​ | 25,000 | ​ | Stacked | ​

(a) | Dynamically positioned.

(b) | Patented dual activity.

(c) | Two blowout preventers.

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

(e) | Enhanced Enterprise-class rig.

(f) | Moored.

(g) | Dual activity.

​

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Markets

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, 2020, our drilling fleet, including stacked and idle rigs, but excluding rigs under construction, was located in the Norwegian North Sea (ten units), the U.S. Gulf of Mexico (eight units), Greece (seven units), the U.K. North Sea (five units), Brazil (three units), Canada (two units), Australia (two units), Malaysia (one unit), Angola (one unit), India (one unit), Egypt (one unit), Brunei (one unit), Equatorial Guinea (one unit), Namibia (one unit), and Romania (one unit).

We categorize the market sectors in which we operate as follows: (1) ultra-deepwater and deepwater, (2) harsh environment and (3) midwater. These market sectors, collectively known as the floater market, are serviced by our drillships and semisubmersibles, 14 of which are suited to work in harsh environments. 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 services water depths from approximately 300 feet to approximately 4,500 feet. The harsh environment market sector services regions that are more challenged by lower temperatures, harsher weather conditions and water currents.

The market for offshore drilling rigs and related services reflects oil companies’ 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 oil companies, independent oil companies and, to a lesser extent, national oil 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.

Since 2014, the industry has experienced a severe, prolonged cyclical downturn. Multiple years of volatile and generally weak commodity prices have resulted in our customers delaying offshore investment decisions and postponing exploration and development programs. Structural efficiency gains achieved by industry participants in reaction to the downturn have provided customers more incentive to progress exploration and development plans in a lower commodity pricing environment, which resulted in increased customer project sanctioning in 2019. We anticipate this trend of increased project sanctioning to continue in 2020 as our customers continue to realize favorable offshore economics, reducing their sensitivity to market volatility, and increasing their focus on exploration and reserve replacement. Ultimately, as the hydrocarbon supply-demand balance improves, we expect a longer term sustained improvement of oil prices, that is expected to translate into greater demand for our fleet, resulting in further improvement of dayrates.

In markets requiring harsh environment floating drilling rigs, the limited supply of these specialized, high-specification rigs has continued to result in strong utilization and dayrate. In the ultra-deepwater markets, persistently improving supply-demand dynamics is now positively impacting both utilization and dayrates. With an increasing number of projects coming from deepwater and ultra-deepwater basins worldwide, we expect this trend to continue.

We have made concerted efforts since the beginning of the downturn to high-grade our fleet profile by acquiring additional high-specification assets and disposing of lower-specification assets. In the year ended December 31, 2018, we significantly enhanced our high-specification asset portfolio with our acquisitions of Songa Offshore SE(“Songa”), a European public company limited by shares, or societas Europaea, existing under the laws of Cyprus, and Ocean Rig UDW Inc. (“Ocean Rig”), a Cayman Islands exempted company with limited liability, and our investment in a partial ownership interest in an unconsolidated affiliate that owns the harsh environment floater Transocean Norge. During the years ended December 31, 2019, 2018 and 2017, we sold for scrap value eleven, eight and three lower-specification drilling units, respectively.

Our outlook for the offshore drilling sector remains positive, particularly for high-specification assets. Brazil, the U.S. Gulf of Mexico, and West Africa remain key ultra-deepwater market sectors, while Norway represents the largest harsh environment market. Licensing activity demonstrated an increased interest in these areas as energy companies looked to explore and develop new prospects. We expect deepwater oil and gas production will continue to be the primary part of the long-term strategy for energy companies as they strive to replace reserves to meet global demand for energy sources and hydrocarbons. As our customers continue to achieve structural efficiency gains, we anticipate additional offshore projects will be sanctioned. Often, these projects are technically demanding due to factors such as water depth, complex well designs, deeper drilling depth, high pressure and temperature, sub-salt, harsh environments, and heightened regulatory standards; therefore, they require 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. See “Item 1A. Risk Factors—Risks related to our business.”

Contract Drilling Services

Our contracts to provide offshore drilling services are individually negotiated and vary in their terms and conditions. We obtain most of our drilling contracts through competitive bidding against other contractors and direct negotiations with operators. Drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods while the drilling unit is operating and lower rates or zero rate for periods of mobilization or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental

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conditions or other conditions beyond our control. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. At December 31, 2019, our contract backlog was approximately $10.4 billion, representing a decrease of 17 percent and an increase of 9 percent, respectively, compared to the contract backlog at December 31, 2018 and 2017, which was $12.5 billion and $9.5 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 upon payment of an early termination payment. Such payments, however, may not fully compensate us for the loss of the contract. 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, in the event of extended downtime or impaired performance caused by 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 term. 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 firm drilling contracts to reduce the term of their obligations or the average dayrate through term extensions, or may seek to repudiate their contracts. Suspension of drilling contracts will result in the reduction in or loss of dayrate for the period of the suspension. 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, if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our consolidated financial position, results of operations or cash flows. 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, our drilling contracts are individually negotiated, and the degree of indemnification we receive from our customers for the risks discussed above may vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. In some instances, we have contractually agreed upon certain limits to our indemnification rights and can be responsible for 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. In most instances in which we are indemnified for damages to the well, we have the responsibility to redrill the well at a reduced dayrate. 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. 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.”

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 will need to consider the specific contract language, the facts and applicable laws. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy. Courts also restrict indemnification for criminal fines and penalties. The inability or other failure of our customers to fulfill their indemnification obligations, or unenforceability of our contractual protections could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Significant Customers

We engage in offshore drilling services for most of the leading integrated oil companies or their affiliates, as well as for many government-owned or government-controlled oil companies and other independent oil companies. For the year ended December 31, 2019, our most significant customers were Royal Dutch Shell plc (together with its affiliates, “Shell”), Equinor ASA (together with its affiliates, “Equinor”) and Chevron Corporation (together with its affiliates, “Chevron”), representing approximately 26 percent, 21 percent and 17 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, 2019. Additionally, as of February 14, 2020, the customers with the most significant aggregate amount of contract backlog associated with our drilling contracts were Shell, Equinor and Chevron, representing approximately 49 percent, 26 percent and 13 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 consolidated financial position, results of operations or cash flows.”

Employees

We require highly skilled personnel to operate our drilling units. Consequently, we conduct extensive personnel recruiting, training and safety programs. At December 31, 2019, we had approximately 6,600 employees, including approximately 700 persons engaged through contract labor providers. Approximately 47 percent of our total workforce, working primarily in Norway, Brazil, the U.K., Angola and

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Australia 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. These negotiations sometimes result in strikes and could result in higher personnel expenses, other increased costs or increased operational restrictions as the outcome of such negotiations affect the market for all offshore employees, not just the union members. Additionally, failure to reach agreement on certain key issues may result in strikes, lockouts or other work stoppages that may materially impact our operations.

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 enter into agency or sponsorship agreements. We may also enter into joint ventures for operational or investment purposes. We may or may not control these joint ventures. At December 31, 2019, we held interests in certain joint venture companies in the Cayman Islands, Nigeria, Angola, Indonesia 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.

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 three 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, two of our drillships under construction will include industry-leading 3 million-pound hook load capability, hybrid power systems for enhanced drill floor equipment reliability, fuel and emissions savings as well as advanced generator protection for power plant reliability. Nine 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. In late 2018, we contracted and are outfitting one drillship that is under construction with a dual 20,000 psi blowout preventer and related equipment. Five drillships in our existing fleet are, and our uncontracted drillship that is under construction will be, designed to accept 20,000 psi blowout preventers in the future.

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. In 2019, we deployed the world’s first hybrid energy storage system aboard a floating drilling unit, the harsh environment floater Transocean Spitsbergen, which is the first solution to reduce fuel consumption and emissions while providing enhanced power management reliability. 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. We have installed automated drilling control systems on one harsh environment floater and are proceeding with five additional harsh environment floaters, which materially improve our ability to safely and efficiently deliver wells to our customers.

We have also deployed our smart equipment analytics tool, which delivers real-time data feeds from equipment and is used to monitor equipment health and inferred emissions and energy consumption. This technology can also identify trends in performance that allow us to systematically optimize equipment maintenance and achieve higher levels of reliability, operational efficiency and sustainability. This data-driven approach, augmented by the size of our fleet, is helping us build a knowledge framework for sustainable process optimization. Additionally, our continued, acute focus on personnel safety has driven development of our HaloGuard system, which will alarm, notify and, if required, halt equipment to avoid injury to personnel who move into danger zones.

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.

Environmental Responsibility

We constantly look for new ways to advance our commitment to safely performing our operations while simultaneously safeguarding the environment in which we operate. We 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.

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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. Although this greater degree of scrutiny requires more of our resources, we are committed to identifying and deploying sustainable solutions throughout the life cycle of our assets.

Our operations are subject to a variety of international, regional, national, state and local environmental regulations. We monitor our compliance with environmental regulation in each country of operation and, while we see an increase in general environmental regulation, we have made and will continue to make the required expenditures to comply with current and future environmental requirements. To date, we have not incurred material costs in order to comply with recent environmental regulation, and 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. For a discussion of the effects of environmental regulation, see “Item 1A. Risk Factors—Risks related to our business—Impact of our compliance with or breach of environmental laws can be costly, expose us to liability and could limit our operations.”

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. 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.

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 the level of activity in oil and gas exploration, development and production in offshore areas worldwide. Demand for our services depends on oil and natural gas industry activity and 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. and other large energy-consuming markets;

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

| ◾ | the level of production in non-OPEC countries;

| ◾ | the policies of various governments regarding exploration and development of their oil and gas reserves;

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

| ◾ | advances in exploration, development and production technology;

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

| ◾ | the discovery rate of new oil and gas reserves;

| ◾ | the rate of decline of existing oil and gas reserves;

| ◾ | laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;

| ◾ | the development and exploitation of alternative energy sources;

| ◾ | 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, oil and natural gas companies, including national oil 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 oil and gas companies could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. 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 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

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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 have responded to increased customer demand by increasing the supply of rigs through ordering the construction of new units. The number of new units expected to be delivered without contracts, combined with the expected increase in the number of rigs in the global market completing contracts and becoming idle, has increased and may further intensify price competition. In periods of low oil and natural gas price levels, new construction has historically resulted in an oversupply of rigs and has caused a subsequent decline in dayrates and rig utilization rates, sometimes for extended periods of time. Any further near-term increase in the construction of new units would likely exacerbate the negative impact of increased supply on dayrates and rig utilization rates. Additional rigs that remain under construction, and the entry into service of these new units will increase overall supply. 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 lower dayrates in exchange for longer contract terms. Lower dayrates and rig utilization rates could adversely affect our revenues and profitability.

As of February 14, 2020, we have 15 uncontracted rigs, and these rigs may remain out of service for extended periods of time. We also have one rig under construction that has not been contracted for work. If we are unable to obtain drilling contracts for our uncontracted rigs, whether due to a prolonged offshore drilling market recovery or otherwise, it may have an adverse effect on our results of operations and cash flows.

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

At February 14, 2020, our contract backlog was approximately $10.2 billion. This amount represents the number of days remaining in the firm term of the drilling contract multiplied by the maximum contractual operating dayrate, excluding revenues for mobilization, demobilization, contract preparation, other incentive provisions or reimbursement revenues, which are generally insignificant to our contract drilling revenues. Our contract backlog includes amounts associated with our contracted newbuild unit that is 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 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 a material adverse effect on our consolidated financial position, results of operations or 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 or our uncontracted newbuild UNIT.

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, 2020, we have 15 stacked or idle rigs and one rig under construction that does not have a customer drilling contract. We also have 11 existing drilling contracts for our rigs that are currently operating, which are scheduled to expire before December 31, 2020. We may be unable to obtain drilling contracts for our rigs that are currently operating upon the expiration or termination of such contracts or

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obtain a drilling contract for our uncontracted newbuild unit, 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 for our uncontracted newbuild unit, 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 consolidated 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 these events are beyond our control. During periods of depressed market conditions, we are subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance. We have experienced, and are at continued risk of experiencing, early contract terminations in a weak commodity price environment as operators look to reduce their capital expenditures. 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 oil 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, it could adversely affect our consolidated financial position, results of operations or cash flows. See “Item 1. Business—Contract Drilling Services.”

We must make substantial capital and operating expenditures to maintain our active fleet or to reactivate our stacked or idle fleet, and we may be required to make significant capital expenditures to maintain our competitiveness, to execute our growth plan 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 execute our growth plan. 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. 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, 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 consolidated financial position, results of operations and cash flows.

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, 2019 and 2018, our total debt was $9.3 billion and $10.0 billion, respectively, of which $3.3 billion and $2.6 billion, respectively, was secured. We have a bank credit agreement, as amended, that established a $1.3 billion secured revolving credit facility (the “Secured Credit Facility”), which is currently undrawn, the borrowings under which would also 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 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;

| ◾ | 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;

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| ◾ | we may be unable to meet financial ratios in the agreements governing certain of our debt and finance lease or satisfy certain other 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; 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.

Our non-credit enhanced senior unsecured long-term debt (our “Debt Rating”) has been rated 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 or replacing 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;

| ◾ | reduced willingness of current and prospective customers to transact business with us;

| ◾ | requirements from creditors 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.

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 consolidated financial position, results of operations or cash flows.

We engage in offshore drilling services for most of the leading integrated oil companies or their affiliates, as well as for many government-owned or government-controlled oil companies and other independent oil companies. For the year ended December 31, 2019, our most significant customers were Shell, Equinor and Chevron, accounting for approximately 26 percent, 21 percent and 17 percent, respectively, of our total contract drilling revenues. As of February 14, 2020, the customers with the most significant aggregate amount of contract backlog were Shell, Equinor and Chevron, representing approximately 49 percent, 26 percent and 13 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 and on our consolidated financial position, results of operations or cash flows.

In addition, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us 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 counterparty, the dayrates received and the level of expenditures necessary to maintain drilling activities. In addition, in depressed market conditions, such as we are currently experiencing, 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. 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 consolidated financial position, results of operations or cash flows.

Worldwide financial, economic and political conditions could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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 current period of low oil and natural gas prices. These potential developments, or market perceptions concerning these and related issues, could affect our consolidated 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 are adding to overall 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

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could reduce demand for our drilling services and have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Public health threats could have a material adverse effect on our business and results of operations.

Public health threats, such as severe influenza, coronaviruses and other highly communicable viruses or diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for hydrocarbons and the level of demand for our services. The quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact our operations and have an adverse effect on our results of operations.

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. 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.

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

As of February 14, 2020, 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:

| ◾ | shipyard availability, failures and difficulties;

| ◾ | shortages of equipment, materials or skilled labor;

| ◾ | unscheduled delays in the delivery of ordered materials and equipment;

| ◾ | 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;

| ◾ | failure or delayed deliveries of significant parts or equipment due to supplier shortages, constraints, disruption or quality issues;

| ◾ | availability of suppliers to recertify equipment for enhanced regulations;

| ◾ | strikes, labor disputes and work stoppages;

| ◾ | customer acceptance delays;

| ◾ | 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 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 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.

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

Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment, including international conventions and treaties, and regional, national, state, and local laws and regulations. The offshore drilling industry 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 or delay exploration and development drilling for oil and gas. Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. A decrease in demand for offshore drilling services due to regulatory restrictions or environmental concerns could have a material adverse effect on our consolidated financial position, results of operations or cash flows. In addition, compliance with environmental laws, regulations and standards, where applicable, may require us to make significant capital expenditures, such as the installation of costly equipment or 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, 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. These costs could have a material adverse effect on our consolidated financial position, results of operations or cash flows. 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.

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 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 consolidated 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. Laws and regulations protecting the environment have become more stringent in recent years, 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 consolidated financial position, results of operations or cash flows.

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

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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 oil companies and may continue to do so.

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, leading to an accumulation of excess local currency balances, which, in certain instances, may be subject to either temporary blocking or other difficulties converting to U.S. dollars, our functional currency, or to other currencies in which we operate. Excess amounts of local currency may be exposed to the risk of currency exchange losses.

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 consolidated financial position, results of operations or cash flows.

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.

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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 oil and natural gas 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 consolidated 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 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.

The continuing effects of the enhanced regulations enacted in the past decade could have an adverse effect on our business and worldwide operations.

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. In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. Operators have had, and may in the future have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico. In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53, related to the installation and testing of well control equipment. These safety and environmental guidelines and standards and any new guidelines or standards the U.S. government or industry may issue or any other steps the U.S. government or industry may take, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in the U.S. and non-U.S. offshore areas.

Other governments could take actions similar to those implemented by the U.S. related to implementing new safety and environmental regulations in the future. Additionally, some of our customers have elected to voluntarily comply with some or all of the non-mandatory inspections, certification requirements and safety and environmental guidelines on rigs operating outside of the U.S. Gulf of Mexico. Additional U.S. and other governmental regulations and requirements concerning licensing, taxation, equipment specifications and training requirements or the voluntary adoption of such requirements or guidelines by our customers could increase the costs of our operations, increase certification and permitting requirements, increase review periods and impose increased liability on offshore operations. The continuing effects of the enhanced regulations may also decrease the demand for drilling services, negatively affect dayrates and increase out-of-service time, which could ultimately have an adverse effect on our revenues and profitability.

Corporate restructuring activity, divestitures, acquisitions and other business combinations and reorganizations could adversely affect our ability to achieve our strategic goals.

We have undertaken and continue to seek appropriate opportunities for restructuring our organization and engaging in strategic divestitures, acquisitions and other business combinations in order to optimize our fleet and strengthen our competitiveness. We face risks arising from these activities, which could adversely affect our ability to achieve our strategic goals, such as the following:

| ◾ | we may be unable to realize the growth or investment opportunities, improvement of our financial position and other expected benefits by these activities in the expected time period or at all;

| ◾ | transactions may not be completed as scheduled or at all due to legal or regulatory requirements, market conditions or contractual and other conditions to which such transactions are subject;

| ◾ | unanticipated adverse consequences could arise in the integration or separation processes, including unanticipated restructuring or separation costs and liabilities, as well as delays or other difficulties in transitioning, coordinating, consolidating, replacing and integrating personnel, information and management systems, and customer products and services; and

| ◾ | the diversion of management and key employees' attention may detract from our ability to increase revenues and minimize costs.

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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 changes in labor laws and regulations.

Approximately 47 percent of our total workforce, primarily employed in Norway, Brazil, the U.K., Angola and Australia 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. These negotiations sometimes result in strikes and could result in higher personnel expenses, other increased costs or increased operational restrictions as the outcome of such negotiations affect the market for all offshore employees, not just the union members. 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.

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 or directors 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 consolidated financial position and results of operations. 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.

Regulatory and various other risks associated with greenhouse gases and climate change could have a negative impact on our business.

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 fossil fuels, is attracting increasing attention worldwide. For example, in December 2015, 195 nations adopted, by consensus, the Paris Agreement, which went into effect in November 2016. The Paris Agreement aims to limit increases in global temperatures to well below two degrees Celsius. While the greenhouse gas emission reductions called for by the Paris Agreement are not binding and the U.S. has initiated the process to withdraw from the agreement, we expect continued and increased attention to climate change. This attention 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-energy 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

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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 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 the investigations and cases involving the Company or our subsidiaries 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 an adverse effect on our financial position, results of operations or cash flows.

Our information technology systems are subject to cybersecurity risks and threats.

We depend on 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. 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. Threats to our systems and our customers’ and vendors’ systems may derive from human error, fraud or malice 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 of intellectual property, proprietary 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. If such a cyber-incident were to occur, it could have a material adverse effect on our business or on our consolidated financial position, results of operations or cash flows.

In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information, including the European Union General Data Protection Regulation and recent California legislation, pose increasingly complex compliance challenges and potentially elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant penalties 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, which may have a material adverse effect on our results of operations.

Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could 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.

We may not realize the anticipated benefits of our acquisitions.

There is a risk that some or all of the expected benefits of our acquisitions may fail to materialize, or may not occur within the time periods anticipated. The realization of such benefits may be affected by a number of factors, many of which are beyond our control, including the strength or weakness of the economy and competitive factors in the areas where we do business, the effects of competition in the markets in which we operate, and the impact of changes in the laws and regulations regulating the offshore drilling industry or affecting domestic or foreign operations. The continued success of the acquisitions, including anticipated benefits and cost savings, will depend, in part, on our ability to successfully market the assets of each of these companies in a manner that results in various benefits, including, among other things, an expanded market reach and operating efficiencies, and that does not materially disrupt existing relationships nor result in

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decreased revenues. Although we expect that the further elimination of duplicative costs, as well as the realization of additional efficiencies related to the integration of the businesses, should allow us to further offset integration-related costs over time, this additional net benefit may not be achieved in the near term, or at all. These costs, as well as other unanticipated costs and expenses, could have an adverse effect on our consolidated financial position, operating results and cash flows. Failure to realize the anticipated further benefits of the acquisitions may impact the financial performance of the combined company.

Other risks

We have significant carrying amounts of long-lived assets that are subject to impairment testing.

At December 31, 2019, the carrying amount of our property and equipment was $18.8 billion, representing 78 percent of our total assets. In accordance with our accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that carrying amounts of our assets held and used may not be recoverable. We also review the carrying amounts of assets at the time that we classify such assets as held for sale. In each of the years ended December 31, 2019, 2018 and 2017, we recognized an aggregate loss of $578 million, $999 million and $1.4 billion, respectively, associated with the impairment of certain assets that we determined were impaired at the time the assets were classified as held for sale. In the year ended December 31, 2017, we also recognized an aggregate loss of $94 million associated with the impairment of our midwater floater asset group. Future expectations of lower dayrates or rig utilization rates or a significant change to the composition of one or more of our asset groups could result in the recognition of additional losses on impairment of our long-lived asset groups if future cash flow expectations, based on information available to management at the time of measurement, indicate that the carrying amount of our asset groups may be impaired.

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 worldwide earnings, which could result in a significant adverse effect on our earnings and cash flows from operations.

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. A material change in the tax laws, treaties or regulations, or their interpretation or application, of or by any country in which we have significant operations, or in which we are incorporated or resident, could result in a higher effective tax rate on our worldwide earnings and such change could be significant to our financial results. Switzerland, for example, has been carefully considering various tax reform proposals in response to certain guidance from and demands by the European Union (the “EU”) and the Organization for Economic Co-operation and Development (the “OECD”) and has enacted a substantial tax reform effective January 2020. Similarly, the OECD 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 have adopted various measures into their own tax laws. In addition, the EU issued its Anti-Tax Avoidance Directives in 2016 and 2017 that required its member states to adopt specific tax reform measures starting in 2019. Other tax jurisdictions in which we operate may consider implementing similar legislation. Any material change to tax laws or policies, their interpretation or the adoption of new interpretations of existing laws and rulings in any of the jurisdictions in which we operate could result in a higher effective tax rate on our worldwide earnings and such change could have a significant adverse effect on our consolidated 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 worldwide earnings, which could result in a significant adverse effect on our earnings and cash flows from operations.

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 cannot be certain that the U.S. Internal Revenue Service (“IRS”) will not successfully contend that we or any of our key subsidiaries were or are engaged in a trade or business in the U.S. or that we or any of our key subsidiaries maintained or maintain a permanent establishment in the U.S. The determination of the aforementioned, among other things, involves considerable uncertainty. If we or any of our key subsidiaries were determined to have been engaged in a trade or business in the U.S. through a permanent establishment, then we could be subject to U.S. corporate income and additional branch profits taxes on the portion of our earnings effectively connected to such U.S. business 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, and our earnings and cash flows from operations for that period could be adversely affected.

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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 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, and such 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.

As a Swiss corporation, our flexibility may be limited with respect to certain aspects of capital management, and we may be unable to make distributions or repurchase shares without subjecting our shareholders to Swiss withholding tax.

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 2018 annual general meeting will expire on May 18, 2020. Our currently available authorized share capital is limited to approximately four percent of our issued share capital as of February 12, 2020. Accordingly, shareholders at our annual general meeting in May 2020 may be requested to approve a renewal and an increase in authorized share capital. Additionally, subject to certain exceptions, Swiss law 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 over which a board of directors would have authority in some other jurisdictions. For example, dividends must be approved by shareholders. These Swiss law requirements relating to our capital management may limit our flexibility, and situations may arise where greater flexibility would have provided substantial benefits to our shareholders.

Distributions to shareholders in the form of a par value reduction and dividend distributions out of qualifying additional paid-in capital are not currently subject to the 35 percent Swiss federal withholding tax. However, the Swiss withholding tax rules could also 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 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.

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Swiss corporate governance may affect our business.

The Swiss Federal Council Ordinance Against Excessive Compensation at Public Companies (the “Ordinance”), among other things, (a) requires a binding shareholder “say on pay” vote with respect to the compensation of members of our executive management and board of directors, (b) generally prohibits the making of severance, advance, transaction premiums and similar payments to members of our executive management team and board of directors, and (c) requires the declassification of our board of directors and the amendment of our articles of association to specify various compensation-related matters. At our annual general meetings, our shareholders are required to approve the maximum aggregate compensation of (1) our board of directors for the period through the successive annual general meeting and (2) our executive management team for the following year. The Ordinance further provides for criminal penalties against directors and members of executive management in case of noncompliance with certain of its requirements. The Ordinance may negatively affect our ability to attract and retain executive management and members of our board of directors.

As a Swiss corporation, we are subject to Swiss legal provisions that may limit our flexibility to swiftly implement certain initiatives or strategies.

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. The 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. The 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. These Swiss law requirements could limit our flexibility to swiftly implement certain initiatives or strategies.

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 18, 2020, to issue a specified number of shares, which under our current authorized share capital is approximately four percent of the share capital registered in the commercial register as of February 12, 2020, 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 23 percent of the share capital registered in the commercial register as of February 12, 2020, 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.

The U.K. withdrawal from the EU may have a negative effect on our business.

On January 31, 2020, the U.K. withdrew from the EU and commenced a transition period that is expected to expire on December 31, 2020 during which the trading relationship between the U.K. and the EU will remain the same while the U.K. and the EU negotiate an agreement regarding their future relationship. There is currently no agreement in place regarding the relationships between the U.K. and the EU after the transition period, creating significant uncertainties. These uncertainties, including with respect to the laws and regulations that will apply as the U.K. determines which EU-derived laws to replace or replicate following the withdrawal may affect our U.K. operations, our customers, suppliers and employees and could have adverse effects on the movement of personnel, goods, information and capital. The withdrawal has also given rise to calls for the governments of other EU member states to consider withdrawal. These developments, or the perception that any of them could occur, have had and may continue to have an adverse effect on global economic

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conditions and the stability of global financial markets, and may reduce global market liquidity and restrict the ability of key market participants to operate in certain financial markets. Any of these factors could depress economic activity and restrict our access to capital, which could have a material adverse effect on our business and on our consolidated financial position, results of operations or cash flows. See “—The global nature of our operations involves additional risks.”

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, 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, South America, Europe, Africa and Asia. We lease most of these facilities.

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 15—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 for the year ended December 31, 2019. 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 12—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 for the year ended December 31, 2019. All such actions, claims, tax and other matters are incorporated herein by reference.

As of December 31, 2019, we were also involved in a number of other lawsuits, claims and disputes, 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. There can be 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.

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, or will, occur; however, there can be no assurance as to the outcome of these matters.

Item 4.Mine Safety Disclosures

Not applicable.

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Executive Officers of the Registrant

We have included the following information, presented as of February 12, 2020, 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 12, 2020 |
Jeremy D. Thigpen (a) |  | President and Chief Executive Officer |  | 45 | ​
Keelan Adamson (a) | ​ | Executive Vice President and Chief Operations Officer | ​ | 50 | ​
Howard E. Davis | ​ | Executive Vice President, Chief Administrative Officer and Chief Information Officer | ​ | 61 | ​
Brady K. Long |  | Executive Vice President and General Counsel |  | 47 | ​
Mark L. Mey (a) |  | Executive Vice President and Chief Financial Officer |  | 56 | ​
David Tonnel |  | Senior Vice President and Chief Accounting Officer |  | 50 | ​

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

Jeremy D. Thigpen is President and 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 Executive Vice President and Chief Operations Officer of the Company. Before being named to his current position in August 2018, Mr. Adamson served 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 12, 2020, we had 612,573,158 shares outstanding and 5,415 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, 2019, the aggregate amount of par value of our outstanding shares was CHF 61 million, equivalent to approximately $63 million, and the aggregate amount of qualifying additional paid-in capital of our outstanding shares was CHF 13.4 billion, equivalent to approximately $13.7 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 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.

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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.

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

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. 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 12, 2020, Transocean Inc., our wholly owned subsidiary, held as treasury shares less than one percent of our issued and outstanding shares as of such date. 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 12, 2020, approximately nine percent of our issued and outstanding 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 2019 | ​ | — | ​ | $ | — | ​ | — |  | $ | 3,352 | ​
November 2019 | ​ | — | ​ | ​ | — | ​ | — | ​ | ​ | 3,352 | ​
December 2019 | ​ | — | ​ | ​ | — | ​ | — | ​ | ​ | 3,352 | ​
Total | ​ | — | ​ | $ | — | ​ | — |  | $ | 3,352 | ​

(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 issued and outstanding shares for an aggregate purchase price of up to CHF 3.5 billion. At December 31, 2019, the authorization remaining under the share repurchase program was for the repurchase of our issued and outstanding shares for an aggregate cost of up to CHF 3.2 billion, equivalent to $3.4 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.”

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Item 6.Selected Financial Data

The selected financial data as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 have been derived from the audited consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” The selected financial data as of December 31, 2017, 2016 and 2015, and for each of the two years in the period ended December 31, 2016 have been derived from our accounting records. The following data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ | ​ | 2019 | ​ | 2018 (a) | ​ | 2017 | ​ | 2016 (b) | ​ | 2015 |
​ | ​ | (In millions, except per share data) |
Statement of operations data | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating revenues |  | $ | 3,088 |  | $ | 3,018 |  | $ | 2,973 |  | $ | 4,161 |  | $ | 7,386 | ​
Operating income (loss) | ​ | ​ | (721) | ​ | ​ | (1,251) | ​ | ​ | (2,505) | ​ | ​ | 1,106 | ​ | ​ | 1,365 | ​
Net income (loss) | ​ | ​ | (1,257) | ​ | ​ | (2,003) | ​ | ​ | (3,097) | ​ | ​ | 827 | ​ | ​ | 897 | ​
Net income (loss) attributable to controlling interest | ​ | ​ | (1,255) | ​ | ​ | (1,996) | ​ | ​ | (3,127) | ​ | ​ | 778 | ​ | ​ | 865 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Per share earnings (loss) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic |  | $ | (2.05) |  | $ | (4.27) |  | $ | (8.00) |  | $ | 2.08 |  | $ | 2.36 | ​
Diluted |  | $ | (2.05) |  | $ | (4.27) |  | $ | (8.00) |  | $ | 2.08 |  | $ | 2.36 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance sheet data (at end of period) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total assets |  | $ | 24,105 |  | $ | 25,665 |  | $ | 22,410 |  | $ | 26,889 |  | $ | 26,431 | ​
Debt due within one year | ​ | ​ | 568 | ​ | ​ | 373 | ​ | ​ | 250 | ​ | ​ | 724 | ​ | ​ | 1,093 | ​
Long-term debt | ​ | ​ | 8,693 | ​ | ​ | 9,605 | ​ | ​ | 7,146 | ​ | ​ | 7,740 | ​ | ​ | 7,397 | ​
Finance lease liability (c) | ​ | ​ | 479 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​
Total equity | ​ | ​ | 11,867 | ​ | ​ | 13,114 | ​ | ​ | 12,711 | ​ | ​ | 15,805 | ​ | ​ | 15,000 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other financial data | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash provided by operating activities |  | $ | 340 |  | $ | 558 |  | $ | 1,170 |  | $ | 1,980 |  | $ | 3,445 | ​
Cash used in investing activities | ​ | ​ | (268) | ​ | ​ | (797) | ​ | ​ | (587) | ​ | ​ | (1,313) | ​ | ​ | (1,932) | ​
Cash provided by (used in) financing activities | ​ | ​ | (312) | ​ | ​ | (147) | ​ | ​ | (1,041) | ​ | ​ | 176 | ​ | ​ | (1,809) | ​
Capital expenditures | ​ | ​ | 387 | ​ | ​ | 184 | ​ | ​ | 497 | ​ | ​ | 1,344 | ​ | ​ | 2,001 | ​
Distributions of qualifying additional paid-in capital | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 381 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Per share distributions of qualifying additional paid-in capital |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 1.05 | ​

(a) | In January 2018, we acquired approximately 97.7 percent ownership interest in Songa. In March 2018, we acquired the remaining shares not owned by us through a compulsory acquisition under Cyprus law and as a result Songa became our wholly owned subsidiary. To complete these transactions, we issued 68.0 million shares and $863 million aggregate principal amount of the Exchangeable Bonds and made an aggregate cash payment of $8 million. In December 2018, we acquired Ocean Rig in a merger transaction, and as a result, Ocean Rig became our wholly owned subsidiary. To complete the acquisition, we issued 147.7 million shares and made an aggregate cash payment of $1.2 billion.

(b) | In December 2016, Transocean Partners LLC, which previously had a portion of its shares publicly traded on the New York Stock Exchange, completed a merger with one of our subsidiaries and subsequently became our wholly owned subsidiary. To complete the merger, we issued 23.8 million shares from conditional capital.

(c) | Effective January 1, 2019, we reclassified our finance lease liability to no longer be presented in long-term debt (see Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 3—Accounting Standards Updates.

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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. The following discussion of our results of operations and liquidity and capital resources includes comparisons for the years ended December 31, 2019 and 2018. For a discussion of comparisons for our results of operations and liquidity and capital resources for the years ended 2018 and 2017, 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, 2018, filed with the United States (“U.S.”) Securities and Exchange Commission on February 19, 2019.

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 12, 2020, we owned or had partial ownership interests in and operated 45 mobile offshore drilling units, including 28 ultra-deepwater floaters, 14 harsh environment floaters and three midwater floaters. As of February 12, 2020, we were constructing two ultra-deepwater drillships.

We provide contract drilling services in a single, global operating segment, which involves contracting our mobile offshore drilling fleet, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding regions of the 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.

Our contract drilling services operations are 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. Our fleet operates in a single, global market for the provision of contract drilling services. 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

Debt issuances—On February 1, 2019, we issued $550 million aggregate principal amount of 6.875% senior secured notes due February 2027 (the “6.875% Senior Secured Notes”), and we received $539 million aggregate cash proceeds, net of discount and issue costs. On May 24, 2019, we issued $525 million aggregate principal amount of 5.375% senior secured notes due May 2023 (the “5.375% Senior Secured Notes”), and we received $517 million aggregate cash proceeds, net of discount and issue costs. On January 17, 2020, we issued $750 million aggregate principal amount of 8.00% senior unsecured notes due February 2027 (the “8.00% Senior Notes”), and we received $743 million aggregate cash proceeds, net of issue costs. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Early debt retirement—During the year ended December 31, 2019, we completed cash tender offers to purchase certain notes (the “2019 Tendered Notes”). In the year ended December 31, 2019, we made an aggregate cash payment of $522 million to settle the validly tendered 2019 Tendered Notes and recognized a loss of $18 million associated with the retirement of debt. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

During the year ended December 31, 2019, we repurchased in the open market $434 million aggregate principal amount of certain of our debt securities. We made an aggregate cash payment of $449 million and recognized an aggregate net loss of $23 million associated with the retirement of such debt. See “—Operating Results” and “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Debt redemption—On January 17, 2020, we provided a notice to redeem in full our outstanding 9.00% senior notes due July 2023 (the “9.00% Senior Notes”), and on February 18, 2020, we made a payment of $767 million, including the make-whole provision, to redeem the notes and in the three months ending March 31, 2020, we expect to recognize a loss of approximately $66 million associated with the retirement of debt. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Impairments—In the year ended December 31, 2019, we recognized an aggregate loss of $583 million primarily associated with the impairment of three ultra-deepwater floaters, along with related assets, which we determined were impaired at the time we classified the assets as held for sale. See “—Operating Results.”

Fleet expansion—We hold a 33.0 percent interest in Orion Holdings (Cayman) Limited (together with its subsidiary, “Orion”), the company that, through its wholly owned subsidiary, owns the harsh environment floater Transocean Norge. In August 2019, Orion completed construction of the rig and placed it into service. One of our subsidiaries operates the rig under a short-term bareboat charter to complete a six-well drilling contract for one of our customers. See “—Liquidity and Capital Resources—Drilling fleet.”

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In October 2019, we agreed with Samsung Heavy Industries Co., Ltd. (“SHI”) to cancel the construction contracts for two ultra-deepwater drillships in exchange for the parties terminating their respective obligations and liabilities under the contracts and our subsidiaries releasing to SHI their respective interests in the rigs. See “—Liquidity and Capital Resources—Drilling fleet.”

Dispositions—During the year ended December 31, 2019, we completed the sale of six ultra-deepwater floaters, one harsh environment floater, two deepwater floaters and two midwater floaters, along with related assets, and we received $64 million in aggregate net cash proceeds. See “—Operating Results” and “—Liquidity and Capital Resources—Drilling fleet.”

Secured Credit Facility—In June 2018, we entered into a bank credit agreement, which established a $1.0 billion secured revolving credit facility (the “Secured Credit Facility”), and in the year ended December 31, 2019, we amended the terms of the agreement to, among other changes, increase the borrowing capacity to $1.3 billion. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Outlook

Drilling market—Our view of the offshore drilling floater market is positive and continues to improve, especially for the highest specification vessels. Contracting activity has strengthened, as both fixture durations and dayrates are increasing. In the past five years, the offshore oil and gas industry has achieved structural efficiency gains that have substantially improved the economics of offshore development projects. These efficiency gains have resulted in project break-even oil prices in the range of $40 per barrel or below in many operating basins, which compares increasingly favorably to onshore shale prospects, and positively impacts our customers’ investment decisions.

Markets requiring high-specification harsh environment floating drilling rigs continue to see high utilization of the active fleet. Over the past year, opportunities have steadily increased for our drilling services, and we have recently observed escalating dayrates in almost all jurisdictions. In particular, we have seen a marked tightening in global demand for ultra-deepwater drilling rigs, especially in the Americas and Australia where dayrates continue to climb. As utilization for ultra-deepwater floaters grows, active supply is approaching full utilization in many regions, and tender activity has increased. As a result, we are seeing some of the highest dayrates since the beginning of the downturn in 2014, particularly for the latest generation and highest capability units. We expect this trend to continue through 2020 and beyond.

As of February 14, 2020, our contract backlog was $10.2 billion compared to $10.8 billion as of October 17, 2019. 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, 2020, the uncommitted fleet rates for each of the five years in the period ending December 31, 2024 were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |
Uncommitted fleet rate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | 50 | % | ​ | 71 | % | ​ | 83 | % | ​ | 83 | % | ​ | 83 | % | ​
Harsh environment floaters | ​ | 45 | % | ​ | 64 | % | ​ | 68 | % | ​ | 83 | % | ​ | 98 | % | ​
Midwater floaters | ​ | 71 | % | ​ | 98 | % | ​ | 100 | % | ​ | 100 | % | ​ | 100 | % | ​

Performance and Other Key Indicators

Contract backlog—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 17, | ​ | February 11, |
​ |  | 2020 |  | 2019 |  | 2019 |
Contract backlog | ​ | (In millions) |
Ultra-deepwater floaters | ​ | $ | 7,282 |  | $ | 7,643 |  | $ | 8,404 | ​
Harsh environment floaters | ​ | ​ | 2,836 | ​ | ​ | 3,074 | ​ | ​ | 3,716 | ​
Midwater floaters | ​ | ​ | 45 | ​ | ​ | 60 | ​ | ​ | 97 | ​
Total contract backlog |  | $ | 10,163 |  | $ | 10,777 |  | $ | 12,217 | ​

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Our contract backlog includes only firm commitments, which are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog includes amounts associated with our contracted newbuild unit that is currently under construction. The contractual operating dayrate may be higher than the actual dayrate we ultimately receive or 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 dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.

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 dayrate during the firm contract period after operations commence.

At February 14, 2020, the contract backlog and average contractual dayrates for our fleet were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | For the years ending December 31, | ​ | ​ | ​ |
​ |  | Total |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | Thereafter |
Contract backlog | ​ | (In millions, except average dayrates) |
Ultra-deepwater floaters |  | $ | 7,282 |  | $ | 1,624 |  | $ | 1,299 | ​ | $ | 858 | ​ | $ | 860 | ​ | $ | 2,641 | ​
Harsh environment floaters | ​ | ​ | 2,836 | ​ | ​ | 952 | ​ | ​ | 765 | ​ | ​ | 704 | ​ | ​ | 377 | ​ | ​ | 38 | ​
Midwater floaters | ​ | ​ | 45 | ​ | ​ | 42 | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​
Total contract backlog |  | $ | 10,163 |  | $ | 2,618 |  | $ | 2,067 | ​ | $ | 1,562 | ​ | $ | 1,237 | ​ | $ | 2,679 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average contractual dayrates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters |  | $ | 420,000 |  | $ | 325,000 |  | $ | 420,000 | ​ | $ | 471,000 | ​ | $ | 471,000 | ​ | $ | 471,000 | ​
Harsh environment floaters | ​ | $ | 396,000 |  | $ | 348,000 |  | $ | 419,000 | ​ | $ | 432,000 | ​ | $ | 428,000 | ​ | $ | 415,000 | ​
Midwater floaters |  | $ | 130,000 |  | $ | 130,000 |  | $ | 130,000 | ​ | $ | — | ​ | $ | — | ​ | $ | — | ​
Total fleet average | ​ | $ | 409,000 |  | $ | 325,000 |  | $ | 418,000 | ​ | $ | 453,000 | ​ | $ | 457,000 | ​ | $ | 471,000 | ​

The actual amounts of revenues earned and the actual periods during 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 revenue to be recognized include customer liquidity issues and contract terminations, which may be available to our customers under certain circumstances.

Average daily revenue—Average daily revenue is defined as contract drilling revenues, excluding revenues for contract terminations, reimbursements and contract intangible amortization, earned per operating day. An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations. The average daily revenue for our fleet was as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2019 |  | 2018 |  | 2017 |
Average daily revenue | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | $ | 337,900 |  | $ | 356,700 | ​ | $ | 472,400 | ​
Harsh environment floaters | ​ | $ | 298,500 | ​ | $ | 296,400 | ​ | $ | 235,900 | ​
Deepwater floaters | ​ | $ | — |  | $ | 186,700 | ​ | $ | 195,200 | ​
Midwater floaters | ​ | $ | 118,400 |  | $ | 99,900 | ​ | $ | 95,600 | ​
High-specification jackups | ​ | $ | — | ​ | ​ | 152,900 | ​ | ​ | 143,900 | ​
Total fleet average daily revenue | ​ | $ | 313,400 |  | $ | 296,200 | ​ | $ | 321,300 | ​

Our average daily revenue fluctuates relative to market conditions and our revenue efficiency. The average daily revenue may be affected by revenues for lump sum bonuses or demobilization fees received from our customers. Our total fleet average daily revenue is also affected by the mix of rig classes being operated, as deepwater floaters, midwater floaters and high-specification jackups are typically contracted at lower dayrates compared to ultra-deepwater floaters and harsh environment floaters. We no longer operate deepwater floaters or high-specification jackups. 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, 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.

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Revenue efficiency—Revenue efficiency is defined as actual contract drilling 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, excluding revenues for contract terminations and reimbursements, the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions. The revenue efficiency rates for our fleet were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2019 |  | 2018 |  | 2017 |
Revenue efficiency |  | ​ | ​ | ​ | ​ | ​ |
Ultra-deepwater floaters | ​ | 99 | % | 96 | % | 96 | %
Harsh environment floaters | ​ | 95 | % | 94 | % | 96 | %
Deepwater floaters | ​ | — | % | 94 | % | 94 | %
Midwater floaters | ​ | 99 | % | 98 | % | 96 | %
High-specification jackups | ​ | — | % | 100 | % | 101 | %
Total fleet average revenue efficiency | ​ | 97 | % | 95 | % | 96 | %

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 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—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, | ​
​ |  | 2019 |  | 2018 |  | 2017 |
Rig utilization |  | ​ |  | ​ |  | ​ |
Ultra-deepwater floaters | ​ | 51 | % | 48 | % | 39 | %
Harsh environment floaters | ​ | 78 | % | 82 | % | 73 | %
Deepwater floaters | ​ | — | % | 93 | % | 73 | %
Midwater floaters | ​ | 37 | % | 41 | % | 38 | %
High-specification jackups | ​ | — | % | 97 | % | 61 | %
Total fleet average rig utilization | ​ | 58 | % | 59 | % | 48 | %

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, classification as held for sale. Accordingly, our rig utilization can increase when idle or stacked units are removed from our drilling fleet.

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Operating Results

Year ended December 31, 2019 compared to the year ended December 31, 2018

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.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2019 | ​ |  | 2018 | ​ |  | Change |  | % Change | ​
​ | ​ | (In millions, except day amounts and percentages) | ​
​ | ​ | ​ | ​ |  | ​ | ​ | ​ |  | ​ | ​ | ​ |  | ​ |
Operating days | ​ | ​ | 9,872 | ​ | ​ |  | 9,706 | ​ | ​ | ​ | 166 | ​ | 2 | %
Average daily revenue | ​ | $ | 313,400 | ​ | ​ | $ | 296,200 | ​ | ​ | $ | 17,200 | ​ | 6 | %
Revenue efficiency | ​ | ​ | 97 | % | ​ | ​ | 95 | % | ​ | ​ | ​ | ​ | ​ | ​
Rig utilization | ​ | ​ | 58 | % | ​ | ​ | 59 | % | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Contract drilling revenues | ​ | $ | 3,088 | ​ | ​ | $ | 3,018 | ​ | ​ | $ | 70 | ​ | 2 | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating and maintenance expense | ​ | ​ | (2,140) | ​ | ​ | ​ | (1,799) | ​ | ​ | ​ | (341) | ​ | (19) | %
Depreciation and amortization expense | ​ | ​ | (855) | ​ | ​ | ​ | (818) | ​ | ​ | ​ | (37) | ​ | (5) | %
General and administrative expense | ​ | ​ | (193) | ​ | ​ | ​ | (188) | ​ | ​ | ​ | (5) | ​ | (3) | %
Loss on impairment | ​ | ​ | (609) | ​ | ​ | ​ | (1,464) | ​ | ​ | ​ | 855 | ​ | 58 | %
Loss on disposal of assets, net | ​ | ​ | (12) | ​ | ​ | ​ | — | ​ | ​ | ​ | (12) | ​ | nm | ​
Operating loss | ​ | ​ | (721) | ​ | ​ | ​ | (1,251) | ​ | ​ | ​ | 530 | ​ | 42 | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expense), net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest income | ​ | ​ | 43 | ​ | ​ | ​ | 53 | ​ | ​ | ​ | (10) | ​ | (19) | %
Interest expense, net of amounts capitalized | ​ | ​ | (660) | ​ | ​ | ​ | (620) | ​ | ​ | ​ | (40) | ​ | (6) | %
Loss on retirement of debt | ​ | ​ | (41) | ​ | ​ | ​ | (3) | ​ | ​ | ​ | (38) | ​ | nm | ​
Other, net | ​ | ​ | 181 | ​ | ​ | ​ | 46 | ​ | ​ | ​ | 135 | ​ | nm | ​
Loss before income tax expense | ​ | ​ | (1,198) | ​ | ​ | ​ | (1,775) | ​ | ​ | ​ | 577 | ​ | 33 | %
Income tax expense | ​ | ​ | (59) | ​ | ​ | ​ | (228) | ​ | ​ | ​ | 169 | ​ | 74 | %
Net loss | ​ | $ | (1,257) | ​ | ​ | $ | (2,003) | ​ | ​ | $ | 746 | ​ | 37 | %

“nm” means not meaningful.

Contract drilling revenues—Contract drilling revenues increased for the year ended December 31, 2019 compared to the year ended December 31, 2018 primarily due to the following: (a) approximately $265 million resulting from operations acquired in the Ocean Rig UDW Inc. (“Ocean Rig”), a Cayman Islands exempted company with limited liability and Songa Offshore SE (“Songa”), a European public company limited by shares, or societas Europaea, existing under the laws of Cyprus acquisitions, (b) approximately $95 million resulting from the reactivation of two rigs, (c) approximately $65 million resulting from higher revenue efficiency and (d) approximately $65 million resulting from the operations of a newbuild ultra-deepwater drillship and a harsh environment semisubmersible placed into service in 2018 and 2019, respectively. These increases were partially offset by the following: (a) approximately $190 million resulting from rigs sold or classified as held for sale, (b) approximately $125 million resulting from contract early terminations and cancellations recognized in the year ended December 31, 2018, (c) approximately $65 million resulting from reduced activity and (d) approximately $45 million resulting from lower dayrates.

Costs and expenses—Operating and maintenance expense increased for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to the following: (a) approximately $265 million resulting from operations acquired in the Ocean Rig acquisition, including the reactivation of two rigs, (b) approximately $90 million resulting from shipyard activities, (c) approximately $45 million resulting from operations of a newbuild ultra-deepwater drillship and a harsh environment semisubmersible placed into service in 2018 and 2019, respectively and (d) approximately $40 million resulting from the reactivation of two rigs. These increases were partially offset by a decrease of approximately $95 million resulting from rigs sold or classified as held for sale.

Depreciation and amortization expense increased for the year ended December 31, 2019, compared to the year ended December 31, 2018, primarily due to approximately $80 million resulting from the rigs acquired in the Songa and Ocean Rig acquisitions, partially offset by approximately $43 million resulting from rigs sold or classified as held for sale.

General and administrative expense increased for the year ended December 31, 2019, compared to the year ended December 31, 2018, primarily due to the following: (a) approximately $10 million resulting from personnel and other costs related to Ocean Rig recognized in the year ended December 31, 2019, (b) approximately $9 million resulting from increased legal and professional fees (c) approximately $7 million resulting from increased rent expense and (d) approximately $4 million resulting from recovery of legal fees recognized in the year ended December 31, 2018. These increases were partially offset by the following decreases: (a) approximately $24 million resulting from acquisition costs recognized in the year ended December 31, 2018 and (b) approximately $4 million resulting from reduced personnel costs, primarily related to the early retirement of certain personnel in the year ended December 31, 2018.

Loss on impairment or disposal of assets—In the year ended December 31, 2019, we recognized an aggregate loss of $583 million, primarily associated with certain assets that we determined were impaired at the time we classified them as held for sale, and

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an aggregate loss of $26 million associated with the impairment of right-of-use assets and leasehold improvements. In the year ended December 31, 2018, we recognized an aggregate loss of $999 million associated with certain assets that we determined were impaired at the time we classified them as held for sale and a loss of $462 million associated with the impairment of goodwill.

In the year ended December 31, 2019, we recognized an aggregate gain of $4 million associated with the sale of six ultra-deepwater floaters, one harsh environment floater, two deepwater floaters and two midwater floaters, along with related assets. In the year ended December 31, 2018, we recognized an aggregate gain of $7 million associated with the sale of six ultra-deepwater floaters, one deepwater floater and one midwater floater, along with related assets. In the year ended December 31, 2019 and 2018, we recognized an aggregate loss of $16 million and $7 million, respectively, associated with the disposal of assets unrelated to rig sales.

Other income and expense—Interest expense, net of amounts capitalized, increased in the year ended December 31, 2019, compared to the year ended December 31, 2018, primarily due to an increase of approximately $147 million primarily resulting from debt issued subsequent to January 1, 2018, partially offset by a decrease of approximately $104 million resulting from the retirement of debt as a result of scheduled maturities, the purchase of the 2019 Tendered Notes and our open market repurchases.

In the year ended December 31, 2019, we recognized a net loss on retirement of debt as follows: (a) $18 million resulting from retirement of the validly tendered 2019 Tendered Notes and (b) $23 million resulting from open market repurchases of $434 million aggregate principal amount of our debt securities.

Other income, net, increased in the year ended December 31, 2019, compared to the year ended December 31, 2018, primarily due to the following: (a) a gain of $132 million resulting from termination of construction contracts in the year ended December 31, 2019 and (b) an net increase of $41 million resulting from currency exchange rate changes, $18 million of which resulted from reduced losses recognized on undesignated currency derivative instruments. Partially offsetting these increases was (a) reduced income of $34 million from our dual-activity patent and (b) reduced income of $6 million from non-service components of net periodic benefit costs.

Income tax expense—In the years ended December 31, 2019 and 2018, our effective tax rate was (4.9) percent and (12.8) percent, respectively, based on loss before income tax expense. In the years ended December 31, 2019 and 2018, the effect of the various discrete period tax items represented a net tax benefit of $150 million and a net tax expense of $143 million, respectively. In the year ended December 31, 2019, such discrete items included a U.S. tax law change, settlements and expirations of various uncertain tax positions and adjustments to our deferred taxes for operating structural changes made in the U.S. In the year ended December 31, 2018, such discrete items were primarily related to the U.S. transition tax on non-U.S. earnings. In the years ended December 31, 2019 and 2018, our effective tax rate, excluding discrete items, was (30.7) percent and (29.2) percent, respectively, based on loss before income tax expense. Our effective tax rate decreased in the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to the recognition of significant uncertain tax benefits, partially offset by increased tax expense related to the adoption of a new operating structure, which will reduce our exposure to the U.S. base erosion and anti-abuse tax and other cash taxes in the U.S. To a lesser extent, our effective tax rate decreased due to changes in the relative blend of income from operations in certain jurisdictions.

Due to factors related 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 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, 2019, a significant portion of our income tax expense was generated in countries in which income taxes are 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, the United Kingdom (“U.K.”) and Norway. 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. For example, two rigs operating in the same country could generate significantly different provisions for income taxes if they are owned by two different subsidiaries that are subject to differing tax laws and regulations in the respective country of incorporation. See Notes to Consolidated Financial Statements—Note 12—Income Taxes.

​

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Liquidity and Capital Resources

Sources and uses of cash

At December 31, 2019, we had $1.8 billion in unrestricted cash and cash equivalents and $558 million in restricted cash and cash equivalents. In the year ended December 31, 2019, our primary sources of cash were as follows: (1) net cash proceeds from the issuance of debt, (2) net cash provided by operating activities and (3) proceeds from maturities of short-term investments. Our primary uses of cash were as follows: (a) repayments of debt, (b) capital expenditures and (c) investments in unconsolidated affiliates.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended | ​ | ​ | ​ |
​ | ​ | December 31, | ​ | ​ | ​ | ​
​ |  | 2019 |  | 2018 |  | Change |
​ | ​ | (In millions) |
Cash flows from operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss | ​ | $ | (1,257) |  | $ | (2,003) |  | $ | 746 | ​
Non-cash items, net | ​ | ​ | 1,898 | ​ | ​ | 2,432 | ​ | ​ | (534) | ​
Changes in operating assets and liabilities, net | ​ | ​ | (301) | ​ | ​ | 129 | ​ | ​ | (430) | ​
​ | ​ | $ | 340 |  | $ | 558 |  | $ | (218) | ​

Net cash provided by operating activities decreased primarily due to increased operating costs resulting from rig reactivations and increased cash interest payments.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended | ​ | ​ | ​ |
​ | ​ | December 31, | ​ | ​ | ​ | ​
​ |  | 2019 |  | 2018 |  | Change |
​ | ​ | (In millions) |
Cash flows from investing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Capital expenditures | ​ | $ | (387) |  | $ | (184) |  | $ | (203) | ​
Proceeds from disposal of assets, net | ​ | ​ | 70 | ​ | ​ | 43 | ​ | ​ | 27 | ​
Cash paid in business combinations, net of unrestricted and restricted cash acquired | ​ | ​ | — | ​ | ​ | (883) | ​ | ​ | 883 | ​
Investments in unconsolidated affiliates | ​ | ​ | (77) | ​ | ​ | (107) | ​ | ​ | 30 | ​
Proceeds from unrestricted and restricted short-term investments, net of deposits | ​ | ​ | 123 | ​ | ​ | 334 | ​ | ​ | (211) | ​
Other, net | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | 3 | ​
​ | ​ | $ | (268) |  | $ | (797) |  | $ | 529 | ​

Net cash used in investing activities decreased primarily due to (a) net cash paid to acquire Songa and Ocean Rig in the year ended December 31, 2018 with no comparable activity in the current year, (b) reduced investments in unconsolidated affiliates, partially offset by (c) reduced proceeds from maturities of unrestricted and restricted investments, net of deposits, and (d) increased capital expenditures.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended | ​ | ​ | ​ |
​ | ​ | December 31, | ​ | ​ | ​ | ​
​ |  | 2019 |  | 2018 |  | Change |
​ | ​ | (In millions) |
Cash flows from financing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proceeds from issuance of debt, net of discounts and issue costs | ​ | $ | 1,056 | ​ | $ | 2,054 | ​ | $ | (998) | ​
Repayments of debt | ​ | ​ | (1,325) | ​ | ​ | (2,105) | ​ | ​ | 780 | ​
Proceeds from investments restricted for financing activities | ​ | ​ | — | ​ | ​ | 26 | ​ | ​ | (26) | ​
Payments to terminate derivative instruments | ​ | ​ | — | ​ | ​ | (92) | ​ | ​ | 92 | ​
Other, net | ​ | ​ | (43) | ​ | ​ | (30) | ​ | ​ | (13) | ​
​ | ​ | $ | (312) |  | $ | (147) |  | $ | (165) | ​

Net cash used in financing activities increased primarily due to (a) reduced cash proceeds from the issuance of the 6.875% Senior Secured Notes and the 5.375% Senior Secured Notes in the year ended December 31, 2019 compared to net cash proceeds from the issuance of the 5.875% senior secured notes due January 2024 (the “5.875% Senior Secured Notes”), the 6.125% senior secured notes due August 2025 (the “6.125% Senior Secured Notes”) and the 7.25% senior notes due November 2025 (the “7.25% Senior Notes”) in the year ended December 31, 2018, partially offset by (b) decreased cash used to repay debt and (c) cash paid to terminate certain derivative instruments assumed in the Songa acquisition in the year ended December 31, 2018 with no comparable activity in the current year.

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Sources and uses of liquidity

Overview—We expect to use existing unrestricted cash balances, internally generated cash flows, borrowings under the Secured Credit Facility, proceeds from the disposal of assets or proceeds from the issuance of additional debt to fulfill anticipated obligations, which may include capital expenditures, working capital and other operational requirements, scheduled debt maturities or other payments. We may also consider establishing additional financing arrangements with banks or other capital providers. Subject to market conditions and other factors, we may also be required to provide collateral for future financing arrangements. In each case subject to then existing market conditions and to our then expected liquidity needs, among other factors, we may continue to use a portion of our internally generated cash flows and proceeds from asset sales to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, or through debt redemptions or tender offers.

Our access to debt and equity markets may be limited due to a variety of events, including, among others, credit rating agency downgrades of our debt ratings, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. The rating of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”) is below investment grade. Such Debt Rating has caused us to experience increased fees and interest rates under agreements governing certain of our senior notes. Further downgrades may affect or limit our ability to access debt markets in the future. Our ability to access such markets may be severely restricted 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 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.

Our internally generated cash flows are directly related to our business and the market sectors in which we operate. 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.

Secured Credit Facility—In June 2018, we entered into a bank credit agreement, which established our $1.0 billion Secured Credit Facility, and in the year ended December 31, 2019, we amended the terms of the agreement to, among other changes, increase the borrowing capacity to $1.3 billion and add to and clarify the lender parties and their respective commitments under the facility. The Secured Credit Facility is scheduled to expire on the earlier of (i) June 22, 2023 and (ii) if greater than $300 million aggregate principal amount of our 9.00% Senior Notes due July 2023 remain outstanding in April 2023, such date. The Secured Credit Facility is guaranteed by Transocean Ltd. and certain subsidiaries. The Secured Credit Facility is secured by, among other things, a lien on the ultra-deepwater floaters Deepwater Asgard, Deepwater Invictus, Deepwater Orion, Deepwater Skyros, Dhirubhai Deepwater KG2 and Discoverer Inspiration and the harsh environment floaters Transocean Barents and Transocean Spitsbergen. The Secured Credit Facility contains covenants that, among other things, include maintenance of certain guarantee and collateral coverage ratios, 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 12, 2020, we had no borrowings outstanding, $9 million of letters of credit issued, and we had $1.3 billion of available borrowing capacity under the Secured Credit Facility.

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 provision, and subsequently, at specified redemption prices.

In February 2019, we issued $550 million aggregate principal amount of 6.875% Senior Secured Notes, and we received aggregate cash proceeds of $539 million, net of discount and issue costs. The indenture that governs the 6.875% Senior Secured Notes contains covenants that, among other things, limit the ability of our subsidiaries that own or operate the collateral rig Deepwater Poseidon to declare or pay dividends to their affiliates. 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 provision, and subsequently, at specified redemption prices.

In May 2019, we issued $525 million aggregate principal amount of 5.375% Senior Secured Notes, and we received aggregate cash proceeds of $517 million, net of discount and issue costs. The indenture that governs the 5.375% Senior Secured Notes contains covenants that, among other things, limit the ability of our subsidiaries that own or operate the collateral rigs Transocean Endurance and Transocean Equinox to declare or pay dividends to their affiliates. We may redeem all or a portion of the 5.375% Senior Secured Notes on

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or prior to May 15, 2021 at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision, and subsequently, at specified redemption prices.

In July 2018, we issued $750 million aggregate principal amount of the 5.875% Senior Secured Notes and $600 million aggregate principal amount of 6.125% Senior Secured Notes (together with the 5.875% Senior Secured Notes, the “2018 Senior Secured Notes”), and we received aggregate cash proceeds of $733 million and $586 million, respectively, net of discount and issue costs. The indentures that govern the 2018 Senior Secured Notes contain covenants that, among other things, limit the ability of our subsidiaries that own or operate the collateral rigs Transocean Enabler, Transocean Encourage and Deepwater Pontus to declare or pay dividends to their affiliates. We may redeem all or a portion of the 2018 Senior Secured Notes on or prior to July 15, 2021 and August 1, 2021, respectively, at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision and subsequently, at specified redemption prices.

In October 2018, we issued $750 million aggregate principal amount of 7.25% Senior Notes, and we received aggregate cash proceeds of $735 million, net of issue costs. We may redeem all or a portion of the 7.25% Senior Notes on or prior to November 1, 2021 at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision, and subsequently, at specified redemption prices.

We will be required to redeem our senior secured notes at a price equal to 100 percent of the aggregate principal amount without a make-whole provision, upon the occurrence of certain events related to the collateral rigs and the related drilling contracts.

Early debt retirement—On January 17, 2020, we provided a notice to redeem in full our outstanding 9.00% Senior Notes. On February 18, 2020, we made a payment of $767 million, including the make-whole provision, to redeem the 9.00% Senior Notes, and in the three months ending March 31, 2020, we expect to recognize a loss of approximately $66 million associated with the retirement of debt.

On February 5, 2019, we completed the 2019 Tender Offers to purchase for cash up to $700 million aggregate purchase price of the 2019 Tendered Notes, subject to the terms and conditions specified in the related offer to purchase. In the year ended December 31, 2019, as a result of the 2019 Tender Offers, we made an aggregate cash payment of $522 million to settle the validly tendered 2019 Tendered Notes. In the years ended December 31, 2019 and 2018, we repurchased in the open market $434 million and $95 million aggregate principal amount of our debt securities, respectively, for an aggregate cash payment of $449 million and $95 million, respectively.

In connection with the Songa acquisition, we assumed rights and obligations under certain credit agreements and a subscription agreement establishing two term loan facilities and a bond facility. In the year ended December 31, 2018, we made an aggregate cash payment of $1.59 billion to repay the borrowings under the facilities and terminated the underlying credit agreements and subscription agreement. We also assumed the indebtedness related to two bond loans and we assumed the rights and obligations under a credit agreement for a secured borrowing facility. In the year ended December 31, 2018, we made an aggregate cash payment equivalent to $67 million to repay the two bond loans and the borrowings outstanding under the secured borrowing facility, and we terminated the underlying credit agreement.

Business combinations—On December 5, 2018, we acquired Ocean Rig in a merger transaction, and as a result, Ocean Rig became our wholly owned subsidiary. To complete the acquisition, we issued 147.7 million shares and made an aggregate cash payment of $1.2 billion.

On January 30, 2018, we acquired an approximate 97.7 percent ownership interest in Songa. On March 28, 2018, we acquired the remaining shares not owned by us through a compulsory acquisition under Cyprus law, and as a result, Songa became our wholly owned subsidiary. To complete these transactions, we issued 68.0 million shares as partial consideration for the acquisition of Songa shares. Additionally, we issued $863 million aggregate principal amount of 0.50% exchangeable senior bonds due January 30, 2023 (the “Exchangeable Bonds”) as partial consideration for the acquisition of Songa shares and partial settlement of certain Songa indebtedness. Holders of the Exchangeable Bonds may convert the notes into shares of Transocean Ltd. at any time prior to maturity at a rate of 97.29756 shares per $1,000 note, equivalent to a conversion price of $10.28 per share, subject to adjustment upon the occurrence of certain events. Holders of Exchangeable Bonds may require us to repurchase all or a portion of such holder’s Exchangeable Bonds upon the occurrence of certain events.

Investments in unconsolidated affiliates—We hold a 33.0 percent ownership interest in Orion, the company that owns the harsh environment floater Transocean Norge. In the years ended December 2019 and 2018, we made an aggregate cash contribution of $74 million and $91 million, respectively, to Orion. Additionally, in the years ended December 31, 2019 and 2018, we made an aggregate cash contribution of $3 million and $16 million, respectively, in certain companies that are involved in researching and developing technology to improve efficiency and reliability and to increase automation, sustainability and safety in drilling and other activities.

Derivative instruments—In connection with the Songa acquisition, we acquired certain currency swaps that were denominated in Norwegian kroner. In February 2018, we made an aggregate cash payment of $92 million in connection with the settlement and termination of the currency swaps.

Litigation settlements—On May 29, 2015, together with the Plaintiff Steering Committee, we filed a settlement agreement (the “PSC Settlement Agreement”) in which we agreed to pay to two classes of plaintiffs a total of $212 million in exchange for a release from all claims against us for damages related to the Macondo well incident. On February 15, 2017, the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”) entered a final order and judgment approving the PSC Settlement Agreement, which is no longer subject to

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appeal, and we subsequently made the required cash deposits into escrow accounts established for settlement. In the years ended December 31, 2019 and 2018, the MDL Court released $33 million and $58 million, respectively, from the escrow account to make payments to plaintiffs. At December 31, 2019, the aggregate balance of our escrow account was $125 million.

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 3.5 billion. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. At February 12, 2020, the authorization remaining under the share repurchase program was for the repurchase of up to CHF 3.2 billion, equivalent to approximately $3.3 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, 2019, our contractual obligations stated at face value, were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | For the years ending December 31, | ​ | ​ | ​ |
​ |  | Total |  | 2020 |  | 2021 - 2022 |  | 2023 - 2024 |  | Thereafter |
​ | ​ | (in millions) |
Contractual obligations | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Debt | ​ | $ | 9,361 |  | $ | 581 |  | $ | 1,243 |  | $ | 3,170 |  | $ | 4,367 | ​
Interest on debt | ​ | ​ | 4,307 | ​ | ​ | 590 | ​ | ​ | 1,059 | ​ | ​ | 767 | ​ | ​ | 1,891 | ​
Finance lease liability | ​ | ​ | 682 | ​ | ​ | 71 | ​ | ​ | 142 | ​ | ​ | 142 | ​ | ​ | 327 | ​
Operating lease liabilities | ​ | ​ | 201 | ​ | ​ | 16 | ​ | ​ | 26 | ​ | ​ | 24 | ​ | ​ | 135 | ​
Purchase obligations | ​ | ​ | 1,116 | ​ | ​ | 1,067 | ​ | ​ | 49 | ​ | ​ | — | ​ | ​ | — | ​
Service agreement obligations | ​ | ​ | 1,035 | ​ | ​ | 110 | ​ | ​ | 237 | ​ | ​ | 253 | ​ | ​ | 435 | ​
Total (a) | ​ | $ | 16,702 |  | $ | 2,435 |  | $ | 2,756 |  | $ | 4,356 |  | $ | 7,155 | ​

(a) | As of December 31, 2019, our defined benefit pension and other postemployment plans represented an aggregate liability of $351 million, representing the aggregate projected benefit obligation, net of the aggregate fair value of plan assets. The carrying amount of this liability is affected by net periodic benefit costs, funding contributions, participant demographics, plan amendments, significant current and future assumptions, and returns on plan assets. Due to the uncertainties resulting from these factors and since the carrying amount is not representative of future liquidity requirements, we have excluded this amount from the contractual obligations presented in the table above. See Notes to Consolidated Financial Statements—Note 14—Postemployment Benefit Plans.

As of December 31, 2019, our unrecognized tax benefits related to uncertain tax positions represented a liability of $175 million. Although a portion of these might settle or reverse in the coming year, there is a high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities, and we excluded this amount from the contractual obligations presented in the table above. See Notes to Consolidated Financial Statements—Note 12—Income Taxes.

Other commercial commitments—We have other commercial commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commercial commitments include 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. Standby letters of credit are issued under various committed and uncommitted credit lines, some of which require cash collateral. At December 31, 2019, the aggregate cash collateral held by banks for letters of credit and surety bonds was $10 million. The obligations that are the subject of these standby letters of credit and surety bonds are primarily geographically concentrated in Brazil, India and Spain. Obligations under these standby letters of credit and surety bonds are not normally called, as we typically comply with the underlying performance requirement.

At December 31, 2019, these obligations stated in U.S. dollar equivalents and their time to expiration were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | ​ | ​ | ​ | For the years ended December 31, | ​ | ​ | ​ |
​ |  | Total |  | 2020 |  | 2021 - 2022 |  | 2023 - 2024 |  | Thereafter |
​ |  | (in millions) |
Other commercial commitments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Standby letters of credit | ​ | $ | 19 |  | $ | 19 | ​ | $ | — | ​ | $ | — | ​ | $ | — | ​
Surety bonds | ​ | ​ | 113 | ​ | ​ | 2 | ​ | ​ | 12 | ​ | ​ | 99 | ​ | ​ | — | ​
Total | ​ | $ | 132 |  | $ | 21 | ​ | $ | 12 | ​ | $ | 99 | ​ | $ | — | ​

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, 2019, the captive insurance company held cash and cash equivalents of $116 million, and such balance is expected to range from $50 million to $136 million through December 31, 2020. The balance of actual cash and cash equivalents held by the captive insurance company varies,

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depending on the premiums paid to the captive insurance company and the timing and number of claims or dividends paid by the captive insurance company.

Drilling fleet

Expansion—From time to time, we review possible acquisitions of businesses and drilling rigs and 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. We may commit to such investment without first obtaining customer contracts. Any acquisition, upgrade or new rig construction 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 secure drilling contracts for rigs under construction could have an adverse effect on our results of operations or cash flows.

In the year ended December 31, 2018, we completed the Songa and Ocean Rig acquisitions to strengthen our position as a leader in the ultra-deepwater and harsh environment drilling services by adding high-value assets. In the year ended December 31, 2018, we also invested in a 33.0 percent ownership interest in Orion, the company that owns the harsh environment floater Transocean Norge. The Moss Maritime CS60 design is considered among the most capable semisubmersibles in the world. In August 2019, Orion completed construction of the rig and placed it into service. One of our subsidiaries operates the rig under a short-term bareboat charter to complete a multiple-well drilling contract for one of our customers. See Notes to Consolidated Financial Statements—Note 4—Business Combinations and Note 5—Unconsolidated Affiliates.

In the years ended December 31, 2019 and 2018, we made capital expenditures of $387 million and $184 million, respectively, including $129 million and $75 million, respectively, for our major construction projects. The historical and projected capital expenditures, capitalized interest and other cash or non-cash capital additions for our ongoing major construction projects were as follows:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Total costs | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | through | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | December 31, | ​ | For the years ending December 31, | ​ | ​ |
​ |  | 2019 |  | 2020 |  | 2021 |  | 2022 |  | Total |
​ | ​ | (In millions) |
Deepwater Atlas (a) | ​ | $ | 329 | ​ | $ | 512 | ​ | $ | 84 | ​ | $ | — | ​ | $ | 925 | ​
Deepwater Titan (b) | ​ | ​ | 309 | ​ | ​ | 204 | ​ | ​ | 629 | ​ | ​ | 8 | ​ | ​ | 1,150 | ​
Total | ​ | $ | 638 |  | $ | 716 |  | $ | 713 |  | $ | 8 |  | $ | 2,075 | ​

(a) | Deepwater Atlas, an ultra-deepwater drillship under construction at the Jurong Shipyard Pte Ltd. in Singapore does not yet have a drilling contract and is contracted to be delivered in the fourth quarter of 2020. Following delivery of the ultra-deepwater drillship, we have included estimated costs of $40 million to mobilize the rig to a location where it may be placed in service.

(b) | Deepwater Titan, an ultra-deepwater drillship under construction at the Jurong Shipyard Pte Ltd. in Singapore, is expected to commence operations in the fourth quarter of 2021. 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 through available cash balances, cash generated from operations and asset sales and financing arrangements with banks or other capital providers. We also have available credit under our Secured Credit Facility (see “—Sources and uses of liquidity”). Economic conditions could impact the availability of these sources of funding.

Dispositions—From time to time, we may review the possible disposition of non-strategic drilling units. Considering recent market conditions, we have committed to plans to sell certain lower-specification drilling units for scrap value. During the years ended December 31, 2019 and 2018, we identified six and eight such drilling units, respectively, that we have sold for scrap value. We continue to evaluate the drilling units in our fleet and may identify additional lower-specification drilling units to be sold for scrap value.

During the year ended December 31, 2019, we completed the sale of six ultra-deepwater floaters, one harsh environment floater, two deepwater floaters and two midwater floaters, along with related assets, and we received net cash proceeds of $64 million. During the year ended December 31, 2018, we completed the sale of six ultra-deepwater floaters, one deepwater floater and one midwater floater, along with related assets, and we received net cash proceeds of $36 million.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2019.

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Related Party Transactions

We engage in certain related party transactions with Orion under a management services agreement for the operation and maintenance of the harsh environment floater Transocean Norge and a shipyard care agreement for the construction of the rig. In the year ended December 31, 2019, we received an aggregate cash payment of $96 million, primarily related to the commissioning, preparation and mobilization of Transocean Norge under the shipyard care agreement. We also lease the rig under a short-term bareboat charter agreement, which is now expected to expire in late 2020. In the year ended December 31, 2019, we recognized rent expense of $8 million, recorded in operating and maintenance costs, and made an aggregate cash payment of $6 million under the bareboat charter agreement. In the year ended December 31, 2019, with other unconsolidated affiliates, we made an aggregate cash payment of $7 million for capital expenditures, primarily for equipment to improve reliability and reduce emissions, and $4 million for research and development, recorded in general and administrative costs. See Notes to Consolidated Financial Statements—Note 5—Unconsolidated Affiliates.

Critical Accounting Policies and Estimates

Overview—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, refer to our Notes to Consolidated Financial Statements—Note 2—Significant Accounting Policies.

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, assets held for sale, goodwill, contingencies, postemployment benefit plans, allowance for excess and obsolete materials and supplies, share-based compensation and allowance for doubtful accounts. 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.

Income taxes—We are a Swiss corporation, operating through our various subsidiaries in a number of countries throughout the world. Our annual tax provision is based on expected taxable income, statutory rates, tax laws and tax planning opportunities available to us in the various jurisdictions in which we operate. The relationship between the provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period because the countries in which we operate have taxation regimes that vary with respect to the nominal tax rate and the availability of deductions, credits and other benefits. Consequently, our income tax expense does not change proportionally with our income before income taxes. Variations also arise when income earned and taxed in a particular country or countries fluctuates from year to year.

The determination of our annual tax provision and evaluation of our tax positions involves interpretation of tax laws in the various jurisdictions and requires significant judgment and 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 of operations or profitability in each jurisdiction. Additionally, we operate in many jurisdictions where the tax laws relating to the offshore drilling industry are not well developed. Although our annual tax provision is based on the best information available at the time, a number of years may elapse before the tax liabilities in the various jurisdictions are ultimately determined.

We establish liabilities for estimated tax exposures in our jurisdictions of operation, and the provisions and benefits resulting from changes to those liabilities are included in our annual tax provision along with related interest. 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, 2019 and 2018, our unrecognized tax benefits were approximately $369 million and $514 million, respectively.

We are undergoing examinations in a number of taxing jurisdictions for various fiscal 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. We do not believe it is possible to reasonably estimate the future impact of changes to the assumptions and estimates related to our annual tax provision because changes to our tax liabilities are dependent on numerous factors that cannot be reasonably projected. These factors include, 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 paid to one country that either produce, or fail to produce, offsetting tax changes in other countries.

We do not provide for taxes on unremitted earnings of subsidiaries when we consider such earnings to be indefinitely reinvested. We recognize deferred taxes related to the earnings of certain subsidiaries that we do not consider to be indefinitely reinvested or that will not be indefinitely reinvested in the future. If we were to distribute from the unremitted earnings of these subsidiaries, we could be subject to taxes payable to various jurisdictions. If facts and circumstances cause us to change our expectations regarding future tax consequences,

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the resulting adjustments to our deferred tax balances could have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Estimates, judgments and assumptions are required in determining whether deferred tax assets will be fully or partially realized. 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 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, 2019 and 2018, in evaluating the projected realizability of our deferred tax assets, we considered our consolidated cumulative loss incurred over the recent three-year period, which 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 12—Income Taxes.

Property and equipment—The recognition of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, requires us to apply judgment related to estimates and assumptions for cost capitalization, useful lives and salvage values of our rigs. At December 31, 2019 and 2018, the carrying amount of our property and equipment was $18.8 billion and $20.4 billion, respectively, representing 78 percent and 80 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. 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. At December 31, 2019, 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 $49 million and a hypothetical one-year decrease would cause an increase in our annual depreciation expense of approximately $40 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 or when carrying amounts of assets held for sale exceed fair value less cost to sell. 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, harsh environment floaters and midwater 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 a Level 3 fair value measurement, 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 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.

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In the years ended December 31, 2019, 2018 and 2017, we recognized a loss of $578 million, $999 million and $1.4 billion, respectively, associated with the impairment of assets that we determined were impaired at the time we classified such assets as held for sale. In the year ended December 31, 2017, we recognized a loss of $94 million ($93 million, net of tax) associated with the impairment of the midwater floater asset group. See Notes to Consolidated Financial Statements—Note 7—Drilling Fleet.

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. We recognize corresponding assets for loss contingencies that we believe are probable of being recovered through insurance. 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 liabilities for legal costs as they are incurred, and we recognize a corresponding asset for those legal costs only if we expect such legal costs to be recovered through insurance. Our estimates involve a significant amount of judgement. Actual results may differ from our estimates.

We have recognized a liability for estimated loss contingencies associated with litigation and investigations resulting from the Macondo well incident that we believe are probable and for which a reasonable estimate can be made. At December 31, 2019 and 2018, the remaining liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $124 million and $158 million, respectively, recorded in other current liabilities, the majority of which is related to our settlement with the PSC. See Notes to Consolidated Financial Statements—Note 15—Commitments and Contingencies.

Accounting Standards Updates

For a discussion of the new accounting standards updates that have had or are expected to have an effect on our consolidated financial statements, see Notes to Consolidated Financial Statements—Note 3—Accounting Standards Updates.

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 15—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. From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities. Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated financial position, results of operations or cash flows. We file federal and local tax returns in several jurisdictions throughout the world. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows. See Notes to Consolidated Financial Statements—Note 12—Income Taxes.

​

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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 nominal amounts and related weighted-average interest rates of our long-term debt instruments by contractual maturity date for the years ending December 31 (in millions, except interest rate percentages):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Scheduled Maturity Date (a) | ​ | ​ | ​ | ​ | ​ | ​ |
​ |  | 2020 | ​ | 2021 | ​ | 2022 | ​ | 2023 | ​ | 2024 | ​ | Thereafter | ​ | Total |  | Fair value |
Debt | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed rate (USD) |  | $ | 581 | ​ | $ | 633 | ​ | $ | 610 | ​ | $ | 2,316 | ​ | $ | 854 | ​ | $ | 4,367 | ​ | $ | 9,361 | ​ | $ | 8,976 | ​
Average interest rate | ​ | ​ | 6.29 | % | ​ | 6.90 | % | ​ | 6.15 | % | ​ | 4.85 | % | ​ | 6.47 | % | ​ | 7.28 | % | ​ | ​ | ​ | ​ | ​ | ​

_______________________________

(a) | Expected maturity amounts are based on the face value of debt.

At December 31, 2019 and 2018, the fair value of our debt, presented above was $8.9 billion and $9.2 billion, respectively. During the year ended December 31, 2019, the fair value of our debt decreased by $236 million due to the following: (a) a decrease of approximately $913 million due to the completion of cash tender offers to purchase certain notes on February 5, 2019 and open market repurchases of certain of our debt securities, (b) a decrease of approximately $544 million due to the reclassification of finance lease contract to lease liabilities and (c) a decrease of $346 million due to the repayment of debt in scheduled installments, partially offset by (d) an increase of approximately $1.1 billion due to the issuance of the 6.875% Senior Secured Notes and the 5.375% Senior Secured Notes and (e) an increase of approximately $448 million due to changes in market prices for our outstanding debt. See Notes to Consolidated Financial Statements—Note 10—Debt.

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 associated with our international operations. Our primary risk management strategy for currency exchange rate risk involves structuring customer contracts to provide for payment in both U.S. dollars, which is our functional currency, and local currency. The portion denominated in local currency is based on our anticipated local currency needs over the contract term. Due to various factors, including customer contract terms, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual local currency needs may vary, resulting in exposure to currency exchange rate risk. We may occasionally enter into forward exchange contracts to satisfy anticipated local currency needs. The effect of fluctuations in currency exchange rates caused by our international operations generally has not had a material impact on our overall operating results. See Notes to Consolidated Financial Statements—Note 21—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, 2019. 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, 2019.

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, 2019, 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, 2019, 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, 2019 and 2018, 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, 2019, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 18, 2020, 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 18, 2020

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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, 2019 and 2018, the related consolidated statements of operations, comprehensive loss, equity and cash flows for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 18, 2020, 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 Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

​ | ​ | Income Taxes
Description of the Matter | ​ | As discussed in Notes 2 and 12 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 is 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.

/s/ Ernst & Young LLP

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

Houston, Texas
February 18, 2020

​

​

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
Contract drilling revenues | ​ | $ | 3,088 | ​ | $ | 3,018 |  | $ | 2,731 | ​
Other revenues | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 242 | ​
​ | ​ | ​ | 3,088 | ​ | ​ | 3,018 | ​ | ​ | 2,973 | ​
Costs and expenses | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating and maintenance | ​ | ​ | 2,140 | ​ | ​ | 1,799 | ​ | ​ | 1,389 | ​
Depreciation and amortization | ​ | ​ | 855 | ​ | ​ | 818 | ​ | ​ | 832 | ​
General and administrative | ​ | ​ | 193 | ​ | ​ | 188 | ​ | ​ | 156 | ​
​ | ​ | ​ | 3,188 | ​ | ​ | 2,805 | ​ | ​ | 2,377 | ​
Loss on impairment | ​ | ​ | (609) | ​ | ​ | (1,464) | ​ | ​ | (1,498) | ​
Loss on disposal of assets, net | ​ | ​ | (12) | ​ | ​ | — | ​ | ​ | (1,603) | ​
Operating loss | ​ | ​ | (721) | ​ | ​ | (1,251) | ​ | ​ | (2,505) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expense), net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest income | ​ | ​ | 43 | ​ | ​ | 53 | ​ | ​ | 43 | ​
Interest expense, net of amounts capitalized | ​ | ​ | (660) | ​ | ​ | (620) | ​ | ​ | (491) | ​
Loss on retirement of debt | ​ | ​ | (41) | ​ | ​ | (3) | ​ | ​ | (55) | ​
Other, net | ​ | ​ | 181 | ​ | ​ | 46 | ​ | ​ | 5 | ​
​ | ​ | ​ | (477) | ​ | ​ | (524) | ​ | ​ | (498) | ​
Loss before income tax expense | ​ | ​ | (1,198) | ​ | ​ | (1,775) | ​ | ​ | (3,003) | ​
Income tax expense | ​ | ​ | 59 | ​ | ​ | 228 | ​ | ​ | 94 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss | ​ | ​ | (1,257) | ​ | ​ | (2,003) | ​ | ​ | (3,097) | ​
Net income (loss) attributable to noncontrolling interest | ​ | ​ | (2) | ​ | ​ | (7) | ​ | ​ | 30 | ​
Net loss attributable to controlling interest | ​ | $ | (1,255) | ​ | $ | (1,996) |  | $ | (3,127) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Loss per share | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | $ | (2.05) | ​ | $ | (4.27) |  | $ | (8.00) | ​
Diluted | ​ | $ | (2.05) | ​ | $ | (4.27) |  | $ | (8.00) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted-average shares outstanding | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 612 | ​ | ​ | 468 | ​ | ​ | 391 | ​
Diluted | ​ | ​ | 612 | ​ | ​ | 468 | ​ | ​ | 391 | ​

​

​

​

​

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In millions)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
Net loss | ​ | $ | (1,257) | ​ | $ | (2,003) | ​ | $ | (3,097) | ​
Net income (loss) attributable to noncontrolling interest | ​ | ​ | (2) | ​ | ​ | (7) | ​ | ​ | 30 | ​
Net loss attributable to controlling interest | ​ | ​ | (1,255) | ​ | ​ | (1,996) | ​ | ​ | (3,127) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Components of net periodic benefit costs before reclassifications | ​ | ​ | (25) | ​ | ​ | 6 | ​ | ​ | — | ​
Components of net periodic benefit costs reclassified to net loss | ​ | ​ | 4 | ​ | ​ | 5 | ​ | ​ | 21 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other comprehensive income (loss) before income taxes | ​ | ​ | (21) | ​ | ​ | 11 | ​ | ​ | 21 | ​
Income taxes related to other comprehensive income | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (28) | ​
Other comprehensive income (loss) | ​ | ​ | (21) | ​ | ​ | 11 | ​ | ​ | (7) | ​
Other comprehensive income attributable to noncontrolling interest | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​
Other comprehensive income (loss) attributable to controlling interest | ​ | ​ | (21) | ​ | ​ | 11 | ​ | ​ | (7) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total comprehensive loss | ​ | ​ | (1,278) | ​ | ​ | (1,992) | ​ | ​ | (3,104) | ​
Total comprehensive income (loss) attributable to noncontrolling interest | ​ | ​ | (2) | ​ | ​ | (7) | ​ | ​ | 30 | ​
Total comprehensive loss attributable to controlling interest | ​ | $ | (1,276) | ​ | $ | (1,985) | ​ | $ | (3,134) | ​

​

​

​

​

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, |
​ |  | 2019 |  | 2018 |
​ | ​ | ​ | ​ | ​ | ​ | ​ |
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 1,790 | ​ | $ | 2,160 | ​
Accounts receivable, net | ​ | ​ | 654 | ​ | ​ | 604 | ​
Materials and supplies, net | ​ | ​ | 479 | ​ | ​ | 474 | ​
Restricted cash accounts and investments | ​ | ​ | 558 | ​ | ​ | 551 | ​
Other current assets | ​ | ​ | 159 | ​ | ​ | 159 | ​
Total current assets | ​ | ​ | 3,640 | ​ | ​ | 3,948 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Property and equipment | ​ | ​ | 24,281 | ​ | ​ | 25,811 | ​
Less accumulated depreciation | ​ | ​ | (5,434) | ​ | ​ | (5,403) | ​
Property and equipment, net | ​ | ​ | 18,847 | ​ | ​ | 20,408 | ​
Contract intangible assets | ​ | ​ | 608 | ​ | ​ | 795 | ​
Deferred income taxes, net | ​ | ​ | 20 | ​ | ​ | 66 | ​
Other assets | ​ | ​ | 990 | ​ | ​ | 448 | ​
Total assets | ​ | $ | 24,105 | ​ | $ | 25,665 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities and equity | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable | ​ | $ | 311 | ​ | $ | 269 | ​
Accrued income taxes | ​ | ​ | 64 | ​ | ​ | 70 | ​
Debt due within one year | ​ | ​ | 568 | ​ | ​ | 373 | ​
Other current liabilities | ​ | ​ | 781 | ​ | ​ | 746 | ​
Total current liabilities | ​ | ​ | 1,724 | ​ | ​ | 1,458 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Long-term debt | ​ | ​ | 8,693 | ​ | ​ | 9,605 | ​
Deferred income taxes, net | ​ | ​ | 266 | ​ | ​ | 64 | ​
Other long-term liabilities | ​ | ​ | 1,555 | ​ | ​ | 1,424 | ​
Total long-term liabilities | ​ | ​ | 10,514 | ​ | ​ | 11,093 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commitments and contingencies | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Shares, CHF 0.10 par value, 639,674,422 authorized, 142,365,398 conditionally authorized, 617,970,525 issued | ​ | ​ | ​ | ​ | ​ | ​ | ​
and 611,871,374 outstanding at December 31, 2019, and 638,285,574 authorized, 143,754,246 conditionally | ​ | ​ | ​ | ​ | ​ | ​ | ​
authorized, 610,581,677 issued and 609,649,291 outstanding at December 31, 2018 | ​ | ​ | 59 | ​ | ​ | 59 | ​
Additional paid-in capital | ​ | ​ | 13,424 | ​ | ​ | 13,394 | ​
Accumulated deficit | ​ | ​ | (1,297) | ​ | ​ | (67) | ​
Accumulated other comprehensive loss | ​ | ​ | (324) | ​ | ​ | (279) | ​
Total controlling interest shareholders’ equity | ​ | ​ | 11,862 | ​ | ​ | 13,107 | ​
Noncontrolling interest | ​ | ​ | 5 | ​ | ​ | 7 | ​
Total equity | ​ | ​ | 11,867 | ​ | ​ | 13,114 | ​
Total liabilities and equity | ​ | $ | 24,105 | ​ | $ | 25,665 | ​

​

​

​

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, | ​
​ |  | 2019 |  | 2018 |  | 2017 |  | 2019 |  | 2018 |  | 2017 |
​ | ​ | Quantity | ​ | Amount | ​
Shares | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | 610 | ​ | 391 | ​ | 389 | ​ | $ | 59 | ​ | $ | 37 | ​ | $ | 36 | ​
Issuance of shares under share-based compensation plans | ​ | 2 | ​ | 3 | ​ | 2 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1 | ​
Issuance of shares in acquisition transactions | ​ | — | ​ | 216 | ​ | — | ​ | ​ | — | ​ | ​ | 22 | ​ | ​ | — | ​
Balance, end of period | ​ | 612 | ​ | 610 | ​ | 391 | ​ | $ | 59 | ​ | $ | 59 | ​ | $ | 37 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Additional paid-in capital | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 13,394 | ​ | $ | 11,031 | ​ | $ | 10,993 | ​
Share-based compensation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | 45 | ​ | ​ | 41 | ​
Issuance of shares in acquisition transactions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 2,101 | ​ | ​ | — | ​
Equity component of convertible debt instruments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 172 | ​ | ​ | — | ​
Acquisition of redeemable noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 53 | ​ | ​ | — | ​
Allocated capital for transactions with holders of noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | (3) | ​ | ​ | — | ​
Other, net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (7) | ​ | ​ | (5) | ​ | ​ | (3) | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 13,424 | ​ | $ | 13,394 | ​ | $ | 11,031 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Retained earnings (accumulated deficit) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | (67) | ​ | $ | 1,929 | ​ | $ | 5,056 | ​
Net loss attributable to controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,255) | ​ | ​ | (1,996) | ​ | ​ | (3,127) | ​
Effect of adopting accounting standards updates | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 25 | ​ | ​ | — | ​ | ​ | — | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | (1,297) | ​ | $ | (67) | ​ | $ | 1,929 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accumulated other comprehensive loss | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | (279) | ​ | $ | (290) | ​ | $ | (283) | ​
Other comprehensive income (loss) attributable to controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (21) | ​ | ​ | 11 | ​ | ​ | (7) | ​
Effect of adopting accounting standards update | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (24) | ​ | ​ | — | ​ | ​ | — | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | (324) | ​ | $ | (279) | ​ | $ | (290) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total controlling interest shareholders’ equity | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 13,107 | ​ | $ | 12,707 | ​ | $ | 15,802 | ​
Total comprehensive loss attributable to controlling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,276) | ​ | ​ | (1,985) | ​ | ​ | (3,134) | ​
Share-based compensation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | 45 | ​ | ​ | 41 | ​
Issuance of shares in acquisition transactions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 2,123 | ​ | ​ | — | ​
Equity component of convertible debt instruments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 172 | ​ | ​ | — | ​
Acquisition of redeemable noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 53 | ​ | ​ | — | ​
Allocated capital for transactions with holders of noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | (3) | ​ | ​ | — | ​
Other, net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | (5) | ​ | ​ | (2) | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 11,862 | ​ | $ | 13,107 | ​ | $ | 12,707 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 7 | ​ | $ | 4 | ​ | $ | 3 | ​
Total comprehensive income (loss) attributable to noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (2) | ​ | ​ | (2) | ​ | ​ | 1 | ​
Recognition of noncontrolling interest in business combination | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 33 | ​ | ​ | — | ​
Acquisition of noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | (31) | ​ | ​ | — | ​
Allocated capital for transactions with holders of noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 3 | ​ | ​ | — | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 5 | ​ | $ | 7 | ​ | $ | 4 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total equity | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance, beginning of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 13,114 | ​ | $ | 12,711 | ​ | $ | 15,805 | ​
Total comprehensive loss | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (1,278) | ​ | ​ | (1,987) | ​ | ​ | (3,133) | ​
Share-based compensation | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 37 | ​ | ​ | 45 | ​ | ​ | 41 | ​
Issuance of shares in acquisition transactions | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 2,123 | ​ | ​ | — | ​
Equity component of convertible debt instruments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 172 | ​ | ​ | — | ​
Recognition of noncontrolling interest in business combination | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 33 | ​ | ​ | — | ​
Acquisition of redeemable noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | 53 | ​ | ​ | — | ​
Acquisition of noncontrolling interest | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | (31) | ​ | ​ | — | ​
Other, net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | (6) | ​ | ​ | (5) | ​ | ​ | (2) | ​
Balance, end of period | ​ | ​ | ​ | ​ | ​ | ​ | ​ | $ | 11,867 | ​ | $ | 13,114 | ​ | $ | 12,711 | ​

​

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ | ​ | 2019 |  | 2018 |  | 2017 |
​ |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
Cash flows from operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss | ​ | $ | (1,257) | ​ | $ | (2,003) | ​ | $ | (3,097) | ​
Adjustments to reconcile to net cash provided by operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Contract intangible asset amortization | ​ | ​ | 187 | ​ | ​ | 112 | ​ | ​ | — | ​
Depreciation and amortization | ​ | ​ | 855 | ​ | ​ | 818 | ​ | ​ | 832 | ​
Share-based compensation expense | ​ | ​ | 37 | ​ | ​ | 45 | ​ | ​ | 41 | ​
Loss on impairment | ​ | ​ | 609 | ​ | ​ | 1,464 | ​ | ​ | 1,498 | ​
Loss on disposal of assets, net | ​ | ​ | 12 | ​ | ​ | — | ​ | ​ | 1,603 | ​
Loss on retirement of debt | ​ | ​ | 41 | ​ | ​ | 3 | ​ | ​ | 55 | ​
Gain on termination of construction contracts | ​ | ​ | (132) | ​ | ​ | — | ​ | ​ | — | ​
Deferred income tax expense (benefit) | ​ | ​ | 248 | ​ | ​ | (16) | ​ | ​ | 89 | ​
Other, net | ​ | ​ | 41 | ​ | ​ | 6 | ​ | ​ | 55 | ​
Changes in deferred revenues, net | ​ | ​ | 43 | ​ | ​ | (139) | ​ | ​ | 33 | ​
Changes in deferred costs, net | ​ | ​ | (33) | ​ | ​ | 34 | ​ | ​ | 54 | ​
Changes in other operating assets and liabilities, net | ​ | ​ | (311) | ​ | ​ | 234 | ​ | ​ | 7 | ​
Net cash provided by operating activities | ​ | ​ | 340 | ​ | ​ | 558 | ​ | ​ | 1,170 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Capital expenditures | ​ | ​ | (387) | ​ | ​ | (184) | ​ | ​ | (497) | ​
Proceeds from disposal of assets, net | ​ | ​ | 70 | ​ | ​ | 43 | ​ | ​ | 350 | ​
Investments in unconsolidated affiliates | ​ | ​ | (77) | ​ | ​ | (107) | ​ | ​ | — | ​
Cash paid in business combinations, net of cash acquired | ​ | ​ | — | ​ | ​ | (883) | ​ | ​ | — | ​
Proceeds from maturities of unrestricted and restricted investments | ​ | ​ | 123 | ​ | ​ | 507 | ​ | ​ | — | ​
Deposits to unrestricted investments | ​ | ​ | — | ​ | ​ | (173) | ​ | ​ | (450) | ​
Other, net | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | 10 | ​
Net cash used in investing activities | ​ | ​ | (268) | ​ | ​ | (797) | ​ | ​ | (587) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proceeds from issuance of debt, net of discounts and issue costs | ​ | ​ | 1,056 | ​ | ​ | 2,054 | ​ | ​ | 1,144 | ​
Repayments of debt | ​ | ​ | (1,325) | ​ | ​ | (2,105) | ​ | ​ | (2,284) | ​
Proceeds from investments restricted for financing activities | ​ | ​ | — | ​ | ​ | 26 | ​ | ​ | 102 | ​
Payments to terminate derivative instruments | ​ | ​ | — | ​ | ​ | (92) | ​ | ​ | — | ​
Other, net | ​ | ​ | (43) | ​ | ​ | (30) | ​ | ​ | (3) | ​
Net cash used in financing activities | ​ | ​ | (312) | ​ | ​ | (147) | ​ | ​ | (1,041) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net decrease in unrestricted and restricted cash and cash equivalents | ​ | ​ | (240) | ​ | ​ | (386) | ​ | ​ | (458) | ​
Unrestricted and restricted cash and cash equivalents, beginning of period | ​ | ​ | 2,589 | ​ | ​ | 2,975 | ​ | ​ | 3,433 | ​
Unrestricted and restricted cash and cash equivalents, end of period | ​ | $ | 2,349 | ​ | $ | 2,589 | ​ | $ | 2,975 | ​

​

​

​

​

See accompanying notes.

​

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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. We specialize in technically demanding sectors of the offshore drilling business with a particular focus on ultra-deepwater and harsh environment drilling services. Our mobile offshore drilling fleet is considered one of the most versatile fleets in the world. We contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis to drill oil and gas wells. As of December 31, 2019, we owned or had partial ownership interests in and operated a fleet of 45 mobile offshore drilling units, including 28 ultra-deepwater floaters, 14 harsh environment floaters and three midwater floaters. As of December 31, 2019, we were constructing two ultra-deepwater drillships.

Note 2—Significant Accounting Policies

Accounting estimates—To prepare financial statements in accordance with accounting principles generally accepted in the U.S., we are required to make 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 allowance for doubtful accounts, allowance for excess and obsolete materials and supplies, property and equipment, assets held for sale, goodwill, income taxes, contingencies, share-based compensation and postemployment benefit plans. We base our estimates and assumptions on historical experience and on various other factors 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 could differ from such estimates.

Fair value measurements—We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. 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 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 apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity. 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 5—Unconsolidated Affiliates and Note 16—Equity.

Business combinations—We apply the acquisition method of accounting for business combinations, under which we record the acquired assets and assumed liabilities at fair value and recognize goodwill to the extent the consideration transferred exceeds the fair value of the net assets acquired. To the extent the fair value of the net assets acquired exceeds the consideration transferred, we recognize a bargain purchase gain. We estimate the fair values of the acquired assets and assumed liabilities as of the date of the acquisition, and our estimates are subject to adjustment through completion, which is in each case within one year of the acquisition date, based on our ongoing assessments of the fair values of property and equipment, intangible assets, other assets and liabilities and our evaluation of tax positions and contingencies. See Note 4—Business Combinations.

Goodwill—We conduct impairment testing for our goodwill annually as of October 1 and more frequently, on an interim basis, when an event occurs or circumstances change that indicate that the fair value of our reporting unit may have declined below its carrying value. We test goodwill at the reporting unit level, which is defined as an operating segment or one level below an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We determined that we have a single reporting unit for this purpose. Before testing goodwill, we consider whether or not to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, as the result of our qualitative assessment, we determine that an impairment test is required, or, alternatively, if we elect to forgo the qualitative assessment, we record an impairment to goodwill to the extent the carrying amount of the reporting unit, including goodwill, exceeds the fair value of the reporting unit. In the year ended December 31, 2018, as a result of an interim goodwill test, we recognized an aggregate loss of $462 million, which had no tax effect, associated with the impairment of our goodwill. See Note 4—Business Combinations and Note 8—Goodwill and Other Intangibles.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Contract intangibles—We recognize contract intangible assets and liabilities related to acquired executory contracts, such as drilling contracts and construction 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 over the expected remaining contract period as a reduction of contract drilling revenues. At December 31, 2019 and 2018, the aggregate carrying amount of our drilling contract intangible assets was $608 million and $795 million, respectively. The construction contract intangible liabilities represent 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. Upon cancellation of the construction contracts, we eliminated the contract intangible liabilities with a corresponding adjustment to earnings. See Note 4—Business Combinations and Note 8—Goodwill and Other Intangibles.

Derivative instruments—We record derivatives on our consolidated balance sheet, measured at fair value. We recognize the gains and losses associated with changes in the fair value of undesignated derivatives in current period earnings. See Note 11—Derivative Instruments.

Revenue recognition—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 full 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, which we recognize 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. To obtain contracts with our customers, we incur costs to prepare a rig for contract and mobilize a rig to the drilling location. We defer pre-operating costs, such as contract preparation and mobilization costs, and recognize such costs on a straight-line basis, consistent with the general pace of activity, in operating and maintenance costs over the estimated contract period. 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 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. See Note 6—Revenues.

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. 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 17—Share Based Compensation Plans.

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, 2019, 2018 and 2017, we capitalized interest costs of $38 million, $37 million and $116 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, 2019, 2018 and 2017, we recognized a net gain of $2 million, a net loss of $38 million and a net loss of $6 million, respectively, related to currency exchange rates.

Income taxes—We provide for income taxes based on the tax laws and rates in effect in the countries in which we operate and earn income. 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. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from year to year.

We measure deferred tax assets and liabilities using enacted tax rates that will apply in the years in which the temporary differences are expected to be recovered or paid. 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. In evaluating our ability to realize deferred tax assets, we consider all

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

available positive and negative evidence, including projected future taxable income and the existence of cumulative losses in recent years. We also record a valuation allowance for deferred tax assets resulting from net operating losses incurred during the year in certain jurisdictions and for other deferred tax assets where, in our opinion, it is more likely than not that the financial statement benefit of these losses will not be realized. Additionally, we record a valuation allowance for foreign tax credit carryforwards to reflect the possible expiration of these benefits prior to their utilization.

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. 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. See Note 12—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.

Short-term investments—We periodically deposit unrestricted excess funds in time deposits and commercial paper with original maturities beyond three months. Such short-term investments are with commercial banks with high credit ratings.

Accounts receivable—We earn our revenues by providing our drilling services to integrated oil companies, government-owned or government-controlled oil companies and other independent oil companies. We evaluate the credit quality of our customers on an ongoing basis, and we may occasionally require collateral or other security to support customer receivables. We establish an allowance for doubtful accounts on a case-by-case basis, considering changes in the financial position of a customer, when we believe the required payment of specific amounts owed to us is unlikely to occur. See Note 3—Accounting Standards Updates.

Materials and supplies—We record materials and supplies at their average cost less an allowance for excess and obsolete items. We estimate the allowance for excess and obsolete items based on historical experience and expectations for future use of the materials and supplies. At December 31, 2019 and 2018, our allowance for excess and obsolete items was $127 million and $134 million, respectively.

Restricted cash accounts and investments—We maintain restricted cash accounts and investments 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 accounts and investments 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. At December 31, 2019, the aggregate carrying amount of our restricted cash accounts and investments was $558 million, recorded in current assets. At December 31, 2018, the aggregate carrying amount of our restricted cash accounts and investments was $552 million, of which $551 million and $1 million was classified in current assets and other assets, respectively. See Note 10—Debt, Note 15—Commitments and Contingencies and Note 20—Financial Instruments.

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, 2019, we had no assets classified as held for sale. At December 31, 2018, the aggregate carrying amount of our assets held for sale, recorded in other current assets, was $25 million. See Note 7—Drilling Fleet.

Property and equipment—The recognition of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, requires us to apply judgment related to estimates and assumptions for cost capitalization, useful lives and salvage values of our rigs. These estimates and assumptions are based on both historical experience and expectations regarding future industry conditions and operations. At December 31, 2019, the aggregate carrying amount of our property and equipment represented approximately 78 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 lives of our drilling units range from 30 to 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

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, harsh environment floaters and midwater 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 contract drilling 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—Drilling Fleet.

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 bonds and the expected timing of future benefit payments.

At December 31, 2019 and 2018, our pension and other postemployment benefit plan obligations represented an aggregate liability of $351 million and $362 million, respectively, and an aggregate asset of $42 million and $47 million, respectively, representing the funded status of the plans. In the years ended December 31, 2019, 2018 and 2017, aggregate net periodic benefit costs were income of $3 million, income of $9 million and costs of $5 million, respectively. See Note 14—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. We recognize corresponding assets for those loss contingencies that we believe are probable of being recovered through insurance. 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 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 Updates

Recently adopted accounting standards

Leases—Effective January 1, 2019, we adopted the accounting standards update that requires lessees to recognize a right-of-use asset and lease liability for virtually all leases and updates previous accounting standards for lessors to align certain requirements with the updates to the revenue recognition accounting standards. We applied the transition method that required us to recognize right-of-use assets, recorded in other assets, and lease liabilities, recorded in other current liabilities and other long-term liabilities, as of the date of our adoption with no adjustment to prior periods. We applied the package of practical expedients that permitted us to carry forward historical lease classifications. For our drilling contracts, we recognize revenues based on the predominant component, which is the service component. As of January 1, 2019, for the finance leases under which we are the lessee, we reclassified to other assets $528 million, representing the unamortized right-of-use asset previously recorded in property and equipment, and we reclassified an aggregate remaining lease liability of $511 million, including $32 million and $479 million recorded in other current liabilities and other long-term liabilities, respectively, previously recorded in debt due within one year and debt. As of January 1, 2019, for operating leases under which we are the lessee, we recorded a non-cash adjustment to recognize an aggregate right-of-use asset of $95 million, recorded in other assets, and a corresponding aggregate remaining lease liability of $133 million, including $15 million and $118 million recorded in other current liabilities and other long-term liabilities, respectively. We have accounted for lease and non-lease components of our operating leases as a single component. We have not recognized right-of-use assets or lease liabilities for our short-term leases. Our adoption did not have and is not expected in the future to have a material effect on our consolidated statements of financial position, operations or cash flows. See Note 9—Leases.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Other comprehensive income—Effective January 1, 2019, we adopted the accounting standards update that allows for a reclassification from accumulated other comprehensive loss to accumulated deficit for stranded tax effects resulting from legislation commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax Act”). As of January 1, 2019, as a result of our adoption, we recorded an increase of $24 million to accumulated deficit with a corresponding decrease to accumulated other comprehensive loss.

Recently issued accounting standards

Financial instruments – credit losses—Effective January 1, 2020, we will adopt the accounting standards update that requires entities to estimate an expected lifetime credit loss on financial assets ranging from short-term trade accounts receivable to long-term financings. The update is effective for annual reporting periods beginning after December 15, 2019, including interim periods within those annual periods. We have established our approach to apply the requirements and do not expect our adoption to have a material effect on our consolidated statements of financial position, operations or cash flows or on the disclosures contained in our notes to consolidated financial statements.

Note 4—Business Combinations

Overview

During the year ended December 31, 2018, we completed the acquisitions of Songa Offshore SE (“Songa”), a European public company limited by shares, or societas Europaea, existing under the laws of Cyprus, and Ocean Rig UDW Inc. (“Ocean Rig”), a Cayman Islands exempted company with limited liability. On January 30, 2018, we acquired an approximate 97.7 percent ownership interest in Songa. On December 5, 2018, we acquired Ocean Rig in a merger transaction. We believe both acquisitions further strengthen our position as a leader in providing ultra-deepwater and harsh environment drilling services by adding additional high-value assets, and the Songa acquisition, supported by significant contract backlog, also strengthens our footprint in harsh environment operating areas. In the years ended December 31, 2018 and 2017, in connection with our acquisitions, we incurred acquisition costs of $24 million and $4 million, respectively, recorded in general and administrative costs and expenses.

We included the operating results of Songa and Ocean Rig in our consolidated results of operations, commencing on the acquisition date, January 30, 2018 and December 5, 2018, respectively. In the year ended December 31, 2018, our consolidated statement of operations includes revenues of $497 million and net income of $87 million associated with the operations of Songa and revenues of $15 million and net loss of $8 million associated with the operations of Ocean Rig. Pro forma combined operating results, assuming the acquisitions were completed as of January 1, 2017, were as follows (in millions, except per share data):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2018 |  | 2017 |
Contract drilling revenues |  | $ | 3,373 | ​ | $ | 4,386 | ​
Net loss | ​ | ​ | (2,124) | ​ | ​ | (3,174) | ​
Per share loss - basic and diluted | ​ | ​ | (3.47) | ​ | ​ | (5.29) | ​

​

Ocean Rig UDW Inc.

Consideration—To complete the acquisition, we issued 147.7 million shares with a per share market value of $9.32, based on the market value of our shares on the acquisition date, and made an aggregate cash payment of $1.2 billion. The aggregate fair value of the consideration transferred in the business combination was as follows (in millions):

​

​ | ​ | ​ | ​ | ​
​ |  | Total |
Consideration transferred | ​ | ​ | ​ | ​
Aggregate fair value of shares issued as partial consideration for Ocean Rig shares | ​ | $ | 1,377 | ​
Aggregate cash paid as partial consideration for Ocean Rig shares |  | ​ | 1,168 | ​
Total consideration transferred in business combination | ​ | $ | 2,545 | ​

​

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Assets and liabilities—The fair values of assets acquired and liabilities assumed, measured as of December 5, 2018, were as follows (in millions):

​

​ | ​ | ​ | ​ | ​
​ |  | Total |
Assets acquired | ​ | ​ | ​ | ​
Cash and cash equivalents |  | $ | 152 | ​
Accounts receivable | ​ | ​ | 76 | ​
Property and equipment | ​ | ​ | 2,205 | ​
Drilling contract intangible assets | ​ | ​ | 275 | ​
Other assets | ​ | ​ | 115 | ​
​ | ​ | ​ | ​ | ​
Liabilities assumed | ​ | ​ | ​ | ​
Accounts payable and other current liabilities | ​ | ​ | 71 | ​
Construction contract intangible liabilities | ​ | ​ | 132 | ​
Other long-term liabilities | ​ | ​ | 54 | ​
Net assets acquired | ​ | $ | 2,566 | ​

​

In the year ended December 31, 2019, we completed our estimates of the fair values of the assets and liabilities. In the years ended December 31, 2019 and 2018, we recognized a gain of $11 million and $10 million, respectively, recorded in other, net, for a cumulative gain of $21 million associated with the bargain purchase, primarily due to the decline in the market value of our shares between the announcement date and the closing date. We estimated the fair value of the rigs and related equipment by applying a combination of 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 markets for the assets in an orderly transaction between participants as of the acquisition date. We estimated the fair value of the drilling contracts by comparing the contractual dayrates over the remaining firm contract term and option periods relative to the projected market dayrates as of the acquisition date. We estimated the fair value of the construction contracts by comparing the contractual future payments and terms relative to the market payments and terms as of the acquisition date. Our estimates of fair value for the drilling units and contract intangibles required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the assets, such as future commodity prices, projected demand for our services, rig availability, rig utilization, dayrates, remaining useful lives of the rigs and discount rates.

Songa Offshore SE

Consideration—To complete the acquisition, we issued 66.9 million shares with a per share market value of $10.99, based on the market value of our shares on the acquisition date. We also issued $854 million aggregate principal amount of 0.50% exchangeable senior bonds due January 30, 2023 (the “Exchangeable Bonds”), comprised of $562 million aggregate principal amount as partial consideration to Songa shareholders and $292 million aggregate principal amount as settlement for certain Songa indebtedness. The aggregate fair value of the consideration transferred in the business combination was as follows (in millions):

​

​ | ​ | ​ | ​
​ |  | Total
Consideration transferred | ​ | ​ | ​
Aggregate fair value of shares issued as partial consideration for Songa shares |  | $ | 735
Aggregate fair value of Exchangeable Bonds issued as partial consideration for Songa shares | ​ | ​ | 675
Consideration transferred to Songa shareholders | ​ | ​ | 1,410
​ | ​ | ​ | ​
Aggregate fair value of Exchangeable Bonds issued for settlement of certain Songa indebtedness | ​ | ​ | 351
Total consideration transferred in business combination | ​ | $ | 1,761

​

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Assets and liabilities—The fair values of assets acquired, liabilities assumed and noncontrolling interest, measured as of January 30, 2018, were as follows (in millions):

​

​ | ​ | ​ | ​
​ |  | Total
Assets acquired | ​ | ​ | ​
Cash and cash equivalents |  | $ | 113
Accounts receivable | ​ | ​ | 115
Other current assets | ​ | ​ | 80
Property and equipment | ​ | ​ | 2,414
Goodwill | ​ | ​ | 462
Contract intangible assets | ​ | ​ | 632
​ | ​ | ​ | ​
Liabilities assumed | ​ | ​ | ​
Accounts payable and other current liabilities | ​ | ​ | 178
Debt | ​ | ​ | 1,768
Other long-term liabilities | ​ | ​ | 76
Net assets acquired | ​ | ​ | 1,794
​ | ​ | ​ | ​
Noncontrolling interest in business combination | ​ | ​ | 33
Controlling interest acquired in business combination | ​ | $ | 1,761

​

In the year ended December 31, 2018, we completed our estimates of the fair values of the assets and liabilities. We estimated the fair value of the rigs and related equipment by applying a combination of 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 markets for the assets in an orderly transaction between participants as of the acquisition date. We estimated the fair value of the drilling contracts by comparing the contractual dayrates over the remaining firm contract term and option periods relative to the projected market dayrates as of the acquisition date. The goodwill resulting from the business combination was attributed to synergies and intangible assets that did not qualify for separate recognition. Our estimates of fair value for these assets required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the assets, such as future commodity prices, projected demand for our services, rig availability, dayrates and discount rates. We estimated the fair value of the debt using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.

Noncontrolling interest—On March 28, 2018, we acquired the remaining Songa shares not owned by us through a compulsory acquisition under Cyprus law, and as a result, Songa became our wholly owned subsidiary. As consideration for the remaining Songa shares, we issued 1.1 million shares and $9 million aggregate principal amount of Exchangeable Bonds and we made an aggregate cash payment of $8 million to Songa shareholders who elected to receive a cash payment or failed to make an election, for an aggregate fair value of $30 million.

Note 5—Unconsolidated Affiliates

Investments—We hold investments in various partially owned, unconsolidated companies. In the years ended December 31, 2019 and 2018, we made an aggregate cash contribution of $74 million and $91 million, respectively, to 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. At December 31, 2019 and 2018, the aggregate carrying amount of our investment in Orion, representing a 33.0 percent ownership interest, was $164 million and $91 million, respectively, recorded in other assets using the equity method of accounting. We also invest in certain companies that are involved in researching and developing technology to improve efficiency and reliability and to increase automation, sustainability and safety in drilling and other activities.

Related party transactions—We engage in certain related party transactions with Orion under a management services agreement for the operation and maintenance of the harsh environment floater Transocean Norge and a shipyard care agreement for the construction of the rig. In the year ended December 31, 2019, we received an aggregate cash payment of $96 million, primarily related to the commissioning, preparation and mobilization of Transocean Norge under the shipyard care agreement. We also lease the rig under a short-term bareboat charter agreement, which is now expected to expire in late 2020. In the year ended December 31, 2019, we recognized rent expense of $8 million, recorded in operating and maintenance costs, and made an aggregate cash payment of $6 million under the bareboat charter agreement. In the year ended December 31, 2019, we made an aggregate cash payment of $7 million to other unconsolidated affiliates, primarily capital expenditures for equipment to improve reliability and reduce emissions, and $4 million for research and development, recorded in general and administrative costs. At December 31, 2019, we had receivables of $26 million, recorded in other current assets, and payables of $9 million, recorded other current liabilities, due from or to all unconsolidated affiliates. At December 31, 2018, we had receivables of $7 million, recorded in other current assets, due from all unconsolidated affiliates.

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Note 6—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 our performance obligation varies by contract. At December 31, 2019, the drilling contract with the longest expected remaining duration, excluding unexercised options, extends through February 2028. In the year ended December 31, 2019, we recognized revenues of $10 million for performance obligations satisfied in previous periods due to certain revenues recognized on a cash basis. In the year ended December 31, 2018, we recognized revenues of $174 million for performance obligations satisfied in previous periods, primarily related to revenues for a customer’s contract termination and certain revenues recognized on a cash basis.

To obtain contracts with our customers, we incur pre-operating costs to prepare a rig for contract and deliver or mobilize the rig to the drilling location. We defer such pre-operating costs and recognize the costs on a straight-line basis, consistent with the general pace of activity, in operating and maintenance costs over the estimated contract period. In the years ended December 31, 2019, 2018 and 2017, we recognized pre-operating costs of $18 million, $45 million and $45 million, respectively. At December 31, 2019 and 2018, the unrecognized pre-operating costs to obtain contracts was $34 million and $2 million, respectively, recorded in other assets.

Disaggregation—We recognized revenues as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2019 | ​
​ |  | U.S. |  | Norway |  | Brazil |  | Other |  | Total |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | $ | 1,264 | ​ | $ | — | ​ | $ | 119 | ​ | $ | 574 | ​ | $ | 1,957 | ​
Harsh environment floaters | ​ | ​ | — | ​ | ​ | 775 | ​ | ​ | — | ​ | ​ | 294 | ​ | ​ | 1,069 | ​
Deepwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6 | ​ | ​ | 1 | ​ | ​ | 7 | ​
Midwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 55 | ​ | ​ | 55 | ​
Total revenues | ​ | $ | 1,264 | ​ | $ | 775 | ​ | $ | 125 | ​ | $ | 924 | ​ | $ | 3,088 | ​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2018 | ​
​ |  | U.S. |  | Norway |  | Brazil |  | Other |  | Total |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | $ | 1,496 | ​ | $ | — | ​ | $ | 26 | ​ | $ | 266 | ​ | $ | 1,788 | ​
Harsh environment floaters | ​ | ​ | — | ​ | ​ | 651 | ​ | ​ | — | ​ | ​ | 323 | ​ | ​ | 974 | ​
Deepwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 84 | ​ | ​ | 40 | ​ | ​ | 124 | ​
Midwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 74 | ​ | ​ | 74 | ​
High-specification jackups | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 58 | ​ | ​ | 58 | ​
Total revenues | ​ | $ | 1,496 | ​ | $ | 651 | ​ | $ | 110 | ​ | $ | 761 | ​ | $ | 3,018 | ​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2017 | ​
​ | ​ | U.S. |  | Norway |  | Brazil |  | Other |  | Total |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ultra-deepwater floaters | ​ | $ | 1,519 | ​ | $ | — | ​ | $ | 235 | ​ | $ | 294 | ​ | $ | 2,048 | ​
Harsh environment floaters | ​ | ​ | 8 | ​ | ​ | 83 | ​ | ​ | — | ​ | ​ | 365 | ​ | ​ | 456 | ​
Deepwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 100 | ​ | ​ | 44 | ​ | ​ | 144 | ​
Midwater floaters | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 153 | ​ | ​ | 153 | ​
High-specification jackups | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 172 | ​ | ​ | 172 | ​
Total revenues | ​ | $ | 1,527 | ​ | $ | 83 | ​ | $ | 335 | ​ | $ | 1,028 | ​ | $ | 2,973 | ​

​

Contract liabilities—We recognize contract liabilities, recorded in other current liabilities and other long-term liabilities, for mobilization, contract preparation, capital upgrades and deferred revenues for declining dayrate contracts using the straight-line method over the remaining contract term. Contract liabilities for our contracts with customers were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​
​ |  | 2019 |  | 2018 |
Deferred contract revenues, recorded in other current liabilities |  | $ | 100 | ​ | $ | 87 | ​
Deferred contract revenues, recorded in other long-term liabilities | ​ | ​ | 429 | ​ | ​ | 399 | ​
Total contract liabilities |  | $ | 529 | ​ | $ | 486 | ​

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2019 |  | 2018 |
Total contract liabilities, beginning of period | ​ | $ | 486 | ​ | $ | 625 | ​
Decrease due to recognition of revenues for goods and services | ​ | ​ | (114) | ​ | ​ | (239) | ​
Increase due to goods and services transferred over time | ​ | ​ | 157 | ​ | ​ | 100 | ​
Total contract liabilities, end of period | ​ | $ | 529 | ​ | $ | 486 | ​

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​

Note 7—Drilling Fleet

Construction work in progress—The changes in our construction work in progress, including capital expenditures and other capital additions, were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
Construction work in progress, beginning of period | ​ | $ | 632 | ​ | $ | 1,392 | ​ | $ | 2,171 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Capital expenditures | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Newbuild construction program | ​ | ​ | 129 | ​ | ​ | 75 | ​ | ​ | 397 | ​
Other equipment and construction projects | ​ | ​ | 258 | ​ | ​ | 109 | ​ | ​ | 100 | ​
Total capital expenditures | ​ | ​ | 387 | ​ | ​ | 184 | ​ | ​ | 497 | ​
Changes in accrued capital additions | ​ | ​ | 20 | ​ | ​ | 4 | ​ | ​ | (23) | ​
Construction work in progress impaired | ​ | ​ | (5) | ​ | ​ | — | ​ | ​ | — | ​
Construction work in progress acquired in business combination | ​ | ​ | — | ​ | ​ | 28 | ​ | ​ | — | ​
Construction work in progress sold | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (289) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Property and equipment placed into service | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Newbuild construction program | ​ | ​ | — | ​ | ​ | (903) | ​ | ​ | (896) | ​
Other property and equipment | ​ | ​ | (281) | ​ | ​ | (73) | ​ | ​ | (68) | ​
Construction work in progress, end of period | ​ | $ | 753 | ​ | $ | 632 | ​ | $ | 1,392 | ​

​

Impairments of assets held and used—During the year ended December 31, 2017, we identified indicators that the asset groups in our contract drilling services reporting unit may not be recoverable. In the year ended December 31, 2017, such indicators included a significant decline in commodity prices and the market value of our stock, a reduction of projected dayrates and a further extension of low utilization rates. In the year ended December 31, 2017, as a result of our testing, we recognized a loss of $94 million ($93 million, or $0.25 per diluted share, net of tax) associated with the impairment of the midwater floater asset group. We measured the fair value of the asset groups by applying a combination of 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 markets for the assets in an orderly transaction between participants as of the measurement date. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our contract drilling services reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates.

Impairments of assets 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. In the year ended December 31, 2018, we recognized an aggregate loss of $999 million ($2.13 per diluted share), which had no tax effect, associated with the impairment of the ultra-deepwater floaters Deepwater Discovery, Deepwater Frontier, Deepwater Millennium and GSF C.R. Luigs, the deepwater floaters Jack Bates and Transocean 706 and the midwater floaters Songa Delta and Songa Trym, 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, 2017, we recognized an aggregate loss of $1.4 billion ($3.59 per diluted share), which had no tax effect, associated with the impairment of the ultra-deepwater floaters Cajun Express, Deepwater Pathfinder, GSF Jack Ryan, Sedco Energy and Sedco Express, the deepwater floater Transocean Marianas and the midwater floaters Transocean Prospect and Transocean Searcher, along with related assets, which we determined were impaired at the time that 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, 2019, in connection with our efforts to dispose of non-strategic assets, 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, 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.

During the year ended December 31, 2018, we completed the sale of the ultra-deepwater floaters Cajun Express, Deepwater Discovery, Deepwater Pathfinder, GSF C.R. Luigs, Sedco Energy and Sedco Express, the deepwater floater

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Transocean Marianas and the midwater floater Songa Trym, along with related assets. In the year ended December 31, 2018, we received aggregate net cash proceeds of $36 million and recognized an aggregate net gain of $7 million ($0.01 per diluted share), which had no tax effect, associated with the disposal of these assets. In the year ended December 31, 2018, we received aggregate net cash proceeds of $7 million and recognized an aggregate net loss of $7 million associated with the disposal of assets unrelated to rig sales.

On May 31, 2017, we completed the sale of 10 high-specification jackups, including GSF Constellation I, GSF Constellation II, GSF Galaxy I, GSF Galaxy II, GSF Galaxy III, GSF Monarch, Transocean Andaman, Transocean Ao Thai, Transocean Honor and Transocean Siam Driller, along with related assets, and novated the contracts relating to the construction of five high-specification jackups, together with related assets. In the year ended December 31, 2017, we received aggregate net cash proceeds of $319 million and recognized an aggregate net loss of $1.6 billion ($4.08 per diluted share), which had no tax effect, associated with the disposal of these assets. Following the completion of the sale, we continued to operate three of these high-specification jackups through completion of the drilling contracts, the last of which was completed in October 2018. In the years ended December 31, 2018 and 2017, excluding our loss on the disposal of these assets, our operating results included income of $44 million and $65 million, respectively, before taxes, associated with the high-specification jackup asset group.

During the year ended December 31, 2017, we also completed the sale of the ultra-deepwater floater GSF Jack Ryan and the midwater floaters GSF Rig 140, Transocean Prospect and Transocean Searcher, along with related assets. In the year ended December 31, 2017, we received aggregate net cash proceeds of $22 million and recognized an aggregate net gain of $9 million ($0.01 per diluted share), which had no tax effect, associated with the disposal of these assets. In the year ended December 31, 2017, we received aggregate net cash proceeds of $9 million and recognized an aggregate net loss of $15 million associated with the disposal of assets unrelated to rig sales.

Assets held for sale—At December 31, 2018, the aggregate carrying amount of our assets held for sale, including the ultra-deepwater floaters Deepwater Frontier and Deepwater Millennium, the deepwater floaters Jack Bates and Transocean 706 and the midwater floater Songa Delta, along with related assets, was $25 million, recorded in other current assets.

Note 8—Goodwill and Other Intangibles

Goodwill—During the three months ended June 30, 2018, we classified as held for sale and impaired three ultra-deepwater floaters (see Note 7—Drilling Fleet). We identified the impairment of these assets as an indicator that our goodwill may be impaired. In the year ended December 31, 2018, as a result of our interim goodwill impairment test, we recognized a loss of $462 million ($0.99 per diluted share), which had no tax effect, associated with the impairment of the full balance of our goodwill. We estimated the fair value of the contract drilling services reporting unit using the income approach. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2019 | ​ | Year ended December 31, 2018 |
​ | ​ | 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 | ​ | $ | (112) | ​ | $ | 795 | ​ | $ | — | ​ | $ | — |  | $ | — | ​
Acquisition | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 907 | ​ | ​ | — | ​ | ​ | 907 | ​
Amortization | ​ | ​ | — | ​ | ​ | (187) | ​ | ​ | (187) | ​ | ​ | — | ​ | ​ | (112) | ​ | ​ | (112) | ​
Balance, end of period |  | $ | 907 | ​ | $ | (299) | ​ | $ | 608 | ​ | $ | 907 | ​ | $ | (112) |  | $ | 795 | ​

​

We recognized drilling contract intangible amortization as a reduction of contract drilling revenues. We expect to amortize the carrying amounts over the remaining contract periods, through March 2024. As of December 31, 2019, the estimated future amortization of contract intangible assets was as follows (in millions):

​

​ | ​ | ​ | ​
​ |  | Total
Years ending December 31, | ​ | ​ | ​
2020 |  | $ | 190
2021 | ​ | ​ | 190
2022 | ​ | ​ | 171
2023 | ​ | ​ | 52
2024 | ​ | ​ | 5
Total carrying amount of contract intangible assets | ​ | $ | 608

​

In connection with our acquisition of Ocean Rig, we acquired contracts related to the construction of two ultra-deepwater drillships Ocean Rig Santorini and Ocean Rig Crete. At December 31, 2018, the gross carrying amount of our construction contract liabilities was $132 million. In October 2019, we agreed with Samsung Heavy Industries Co., Ltd. (“SHI”) to cancel the construction contracts for the

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drillships in exchange for the parties terminating their respective obligations and liabilities under the construction contracts and our subsidiaries releasing to SHI their respective interests in the rigs. As a result, in the three months ended December 31, 2019, we eliminated the construction contract intangible liabilities and recognized income of $132 million, recorded in other income, net.

Note 9—Leases

Our operating leases are principally for office space, storage facilities, operating equipment and land. At December 31, 2019, our operating leases had a weighted average discount rate of 6.3 percent and a weighted-average remaining lease term of 13.8 years.

Our finance lease for the ultra-deepwater drillship Petrobras 10000, which is scheduled to expire in August 2029, has an implicit interest rate of 7.8 percent and requires scheduled payments of $6 million monthly through expiration, after which we have the right and obligation to acquire the drillship from the lessor for one dollar. In the year ended December 31, 2019, we recognized expense of $21 million, recorded in depreciation and amortization, associated with the amortization of the right of use asset.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Year ended | ​
​ | ​ | ​ | ​ | December 31, | ​
​ |  | ​ |  | 2019 |
Lease costs | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating lease costs | ​ | ​ | ​ | ​ | $ | 25 | ​
Short-term lease costs | ​ | ​ | ​ | ​ | ​ | 13 | ​
Finance lease costs, amortization of right-of-use assets | ​ | ​ | ​ | ​ | ​ | 21 | ​
Finance lease costs, interest on lease liabilities | ​ | ​ | ​ | ​ | ​ | 39 | ​
Total lease costs | ​ | ​ | ​ | ​ | $ | 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 had vacated or had committed to sublease.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Year ended | ​
​ | ​ | ​ | ​ | December 31, | ​
​ | ​ | ​ |  | 2019 | ​
Cash paid for amounts included in the measurement of lease liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating cash flows from operating leases | ​ | ​ | ​ | ​ | $ | 19 | ​
Operating cash flows from finance lease | ​ | ​ | ​ | ​ | ​ | 39 | ​
Financing cash flows from finance lease | ​ | ​ | ​ | ​ | ​ | 32 | ​

​

At December 31, 2019, the aggregate future minimum rental payments for our leases were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Operating |  | Finance | ​
​ |  | leases |  | lease |
Years ending December 31, | ​ | ​ | ​ | ​ | ​ | ​ | ​
2020 | ​ | $ | 16 | ​ | $ | 71 | ​
2021 | ​ | ​ | 12 | ​ | ​ | 71 | ​
2022 | ​ | ​ | 14 | ​ | ​ | 71 | ​
2023 | ​ | ​ | 12 | ​ | ​ | 71 | ​
2024 | ​ | ​ | 12 | ​ | ​ | 71 | ​
Thereafter | ​ | ​ | 135 | ​ | ​ | 327 | ​
Total future minimum rental payment | ​ | ​ | 201 | ​ | ​ | 682 | ​
Less amount representing imputed interest | ​ | ​ | (72) | ​ | ​ | (203) | ​
Present value of future minimum rental payments | ​ | ​ | 129 | ​ | ​ | 479 | ​
Less current portion, recorded in other current liabilities | ​ | ​ | (13) | ​ | ​ | (35) | ​
Long-term lease liabilities, recorded in other long-term liabilities | ​ | $ | 116 | ​ | $ | 444 | ​

​

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Note 10—Debt

Overview

Outstanding debt—The aggregate principal amounts and aggregate carrying amounts, net of debt-related balances, including unamortized discounts, premiums, issue costs and fair value adjustments of our debt, were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Principal amount | ​ | ​ | Carrying amount |
​ | ​ | December 31, | ​ | December 31, |  | ​ | December 31, | ​ | December 31, |
​ |  | 2019 |  | 2018 |  |  | 2019 |  | 2018 |
6.50% Senior Notes due November 2020 (a) | ​ | $ | 206 | ​ | $ | 286 | ​ | ​ | $ | 206 | ​ | $ | 288 | ​
6.375% Senior Notes due December 2021 (a) | ​ | ​ | 222 | ​ | ​ | 328 | ​ | ​ | ​ | 221 | ​ | ​ | 327 | ​
5.52% Senior Secured Notes due May 2022 (b) | ​ | ​ | 200 | ​ | ​ | 282 | ​ | ​ | ​ | 198 | ​ | ​ | 280 | ​
3.80% Senior Notes due October 2022 (a) | ​ | ​ | 190 | ​ | ​ | 411 | ​ | ​ | ​ | 189 | ​ | ​ | 408 | ​
0.50% Exchangeable Bonds due January 2023 (a) | ​ | ​ | 863 | ​ | ​ | 863 | ​ | ​ | ​ | 862 | ​ | ​ | 862 | ​
5.375% Senior Secured Notes due May 2023 (d) | ​ | ​ | 525 | ​ | ​ | — | ​ | ​ | ​ | 518 | ​ | ​ | — | ​
9.00% Senior Notes due July 2023 (c) | ​ | ​ | 714 | ​ | ​ | 1,250 | ​ | ​ | ​ | 701 | ​ | ​ | 1,221 | ​
5.875% Senior Secured Notes due January 2024 (d) | ​ | ​ | 667 | ​ | ​ | 750 | ​ | ​ | ​ | 656 | ​ | ​ | 735 | ​
7.75% Senior Secured Notes due October 2024 (d) | ​ | ​ | 420 | ​ | ​ | 480 | ​ | ​ | ​ | 412 | ​ | ​ | 469 | ​
6.25% Senior Secured Notes due December 2024 (d) | ​ | ​ | 437 | ​ | ​ | 500 | ​ | ​ | ​ | 430 | ​ | ​ | 489 | ​
6.125% Senior Secured Notes due August 2025 (d) | ​ | ​ | 534 | ​ | ​ | 600 | ​ | ​ | ​ | 525 | ​ | ​ | 588 | ​
7.25% Senior Notes due November 2025 (c) | ​ | ​ | 750 | ​ | ​ | 750 | ​ | ​ | ​ | 737 | ​ | ​ | 736 | ​
7.50% Senior Notes due January 2026 (c) | ​ | ​ | 750 | ​ | ​ | 750 | ​ | ​ | ​ | 743 | ​ | ​ | 742 | ​
6.875% Senior Secured Notes due February 2027 (d) | ​ | ​ | 550 | ​ | ​ | — | ​ | ​ | ​ | 541 | ​ | ​ | — | ​
7.45% Notes due April 2027 (a) | ​ | ​ | 88 | ​ | ​ | 88 | ​ | ​ | ​ | 86 | ​ | ​ | 86 | ​
8.00% Debentures due April 2027 (a) | ​ | ​ | 57 | ​ | ​ | 57 | ​ | ​ | ​ | 57 | ​ | ​ | 57 | ​
7.00% Notes due June 2028 (e) | ​ | ​ | 300 | ​ | ​ | 300 | ​ | ​ | ​ | 306 | ​ | ​ | 306 | ​
Finance lease contract due August 2029 | ​ | ​ | — | ​ | ​ | 511 | ​ | ​ | ​ | — | ​ | ​ | 511 | ​
7.50% Notes due April 2031 (a) | ​ | ​ | 588 | ​ | ​ | 588 | ​ | ​ | ​ | 585 | ​ | ​ | 585 | ​
6.80% Senior Notes due March 2038 (a) | ​ | ​ | 1,000 | ​ | ​ | 1,000 | ​ | ​ | ​ | 991 | ​ | ​ | 991 | ​
7.35% Senior Notes due December 2041 (a) | ​ | ​ | 300 | ​ | ​ | 300 | ​ | ​ | ​ | 297 | ​ | ​ | 297 | ​
Total debt | ​ | ​ | 9,361 | ​ | ​ | 10,094 | ​ | ​ | ​ | 9,261 | ​ | ​ | 9,978 | ​
Less debt due within one year | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
6.50% Senior Notes due November 2020 (a) | ​ | ​ | 206 | ​ | ​ | — | ​ | ​ | ​ | 206 | ​ | ​ | — | ​
5.52% Senior Secured Notes due May 2022 (b) | ​ | ​ | 88 | ​ | ​ | 83 | ​ | ​ | ​ | 87 | ​ | ​ | 81 | ​
5.375% Senior Secured Notes due May 2023 (d) | ​ | ​ | 16 | ​ | ​ | — | ​ | ​ | ​ | 14 | ​ | ​ | — | ​
5.875% Senior Secured Notes due January 2024 (d) | ​ | ​ | 83 | ​ | ​ | 83 | ​ | ​ | ​ | 79 | ​ | ​ | 79 | ​
7.75% Senior Secured Notes due October 2024 (d) | ​ | ​ | 60 | ​ | ​ | 60 | ​ | ​ | ​ | 58 | ​ | ​ | 58 | ​
6.25% Senior Secured Notes due December 2024 (d) | ​ | ​ | 62 | ​ | ​ | 62 | ​ | ​ | ​ | 60 | ​ | ​ | 60 | ​
6.125% Senior Secured Notes due August 2025 (d) | ​ | ​ | 66 | ​ | ​ | 66 | ​ | ​ | ​ | 64 | ​ | ​ | 63 | ​
Finance lease contract due August 2029 | ​ | ​ | — | ​ | ​ | 32 | ​ | ​ | ​ | — | ​ | ​ | 32 | ​
Total debt due within one year | ​ | ​ | 581 | ​ | ​ | 386 | ​ | ​ | ​ | 568 | ​ | ​ | 373 | ​
Total long-term debt |  | $ | 8,780 | ​ | $ | 9,708 | ​ |  | $ | 8,693 | ​ | $ | 9,605 | ​

(a) | Transocean Inc., a 100 percent owned direct subsidiary of Transocean Ltd., is the issuer of the notes and debentures. Transocean Ltd. has provided a full and unconditional guarantee of the notes and debentures. Transocean Ltd. has no independent assets or operations, and its other subsidiaries not owned indirectly through Transocean Inc. were 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. Except as discussed under “Indentures,” 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.

(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. See “—Debt issuances—Senior secured notes.”

(c) | Transocean Inc. is the issuer of the unregistered notes. The priority guaranteed senior unsecured notes, which rank equal in right of payment of all of our existing and future unsecured unsubordinated obligations and rank structurally senior to the extent of the value of the assets of the subsidiaries guaranteeing the notes, are fully and unconditionally, jointly and severally, guaranteed by Transocean Ltd. and certain wholly owned subsidiaries of Transocean Inc. See “—Debt issuances—Priority guaranteed senior unsecured notes.”

(d) | 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. See “—Debt issuances—Senior secured notes.”

(e) | The subsidiary issuer of the registered notes is a wholly owned indirect subsidiary of Transocean Inc. Transocean Inc. has provided a full and unconditional guarantee of the notes and debentures.

​

See Note 23—Subsequent Events.

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Scheduled maturities—At December 31, 2019, the scheduled maturities of our debt were as follows (in millions):

​

​ | ​ | ​ | ​ | ​
​ |  | Total |
Years ending December 31, | ​ | ​ | ​ | ​
2020 | ​ | $ | 581 | ​
2021 | ​ | ​ | 633 | ​
2022 | ​ | ​ | 610 | ​
2023 | ​ | ​ | 2,316 | ​
2024 | ​ | ​ | 854 | ​
Thereafter | ​ | ​ | 4,367 | ​
Total principal amount of debt | ​ | ​ | 9,361 | ​
Total debt-related balances, net | ​ | ​ | (100) | ​
Total carrying amount of debt | ​ | $ | 9,261 | ​

​

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.

Additionally, 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 “5.875% Senior Secured Notes”), 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 (the “6.125% Senior Secured Notes”) 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.

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, 2019, the interest rate in effect for the 6.375% senior notes due December 2021, the 3.80% senior notes due October 2022 and the 7.35% senior notes due December 2041 was 8.375 percent, 5.80 percent and 9.35 percent, respectively.

Secured Credit Facility—In June 2018, we entered into a bank credit agreement, which established a $1.0 billion secured revolving credit facility (the “Secured Credit Facility”), and in May, July, September and December 2019, we amended the terms of the Secured Credit Facility to, among other changes, increase the borrowing capacity to $1.3 billion and add to and clarify the lender parties and their respective commitments under the facility. The Secured Credit Facility is scheduled to expire on the earlier of (i) June 22, 2023 and (ii) if greater than $300 million aggregate principal amount of our 9.00% senior notes due July 2023 (the “9.00% Senior Notes”) remain outstanding in April 2023, such date. 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 Invictus, Deepwater Orion, Deepwater Skyros, Dhirubhai Deepwater KG2 and Discoverer Inspiration and the harsh environment floaters Transocean Barents and Transocean Spitsbergen, the aggregate carrying amount of which was $4.4 billion at December 31, 2019. The Secured Credit Facility contains covenants that, among other things, include maintenance of certain guarantee and collateral coverage ratios, 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, 2019, based on the credit rating of the Secured Credit Facility on that date, the Secured Credit Facility Margin was 2.875 percent and the facility fee was 0.625 percent. At December 31, 2019, we had no borrowings outstanding, $13 million of letters of credit issued, and we had $1.3 billion of available borrowing capacity under the Secured Credit Facility.

Debt issuances

Priority guaranteed senior unsecured notes—On October 25, 2018, we issued $750 million aggregate principal amount of 7.25% senior unsecured notes due November 2025 (the “7.25% Senior Notes”), and we received aggregate cash proceeds of $735 million, net of issue costs. We may redeem all or a portion of the 7.25% Senior Notes on or prior to November 1, 2021 at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision, and subsequently, at specified redemption prices.

On October 17, 2017, we completed an offering of an aggregate principal amount of $750 million of 7.50% senior unsecured notes due January 15, 2026 (the “7.50% Senior Notes”), and we received aggregate cash proceeds of $742 million, net of issue costs. We may

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

redeem all or a portion of the 7.50% Senior Notes on or prior to January 15, 2021 at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision, and subsequently, at specified redemption prices.

Senior secured notes—On February 1, 2019, we issued $550 million aggregate principal amount of 6.875% Senior Secured Notes, and we received approximately $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 were required to deposit $19 million in restricted cash accounts to satisfy debt service requirements. We are required to pay semiannual installments of (a) interest only through August 2021 and (b) principal and interest thereafter. 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 provision, 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 approximately $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 were required to deposit $14 million in restricted cash accounts to satisfy debt service requirements. We are required to pay semiannual installments of (a) interest only through May 2020 and (b) principal and interest thereafter. 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 provision, and subsequently, at specified redemption prices.

In July 2018, we issued $750 million aggregate principal amount of 5.875% Senior Secured Notes and $600 million aggregate principal amount of 6.125% Senior Secured Notes, and we received aggregate cash proceeds of $733 million and $586 million, respectively, net of discount and issue costs. The 5.875% Senior Secured Notes are secured by the assets and earnings associated with the harsh environment floaters Transocean Enabler and Transocean Encourage and the equity of the wholly owned subsidiaries that own or operate the collateral rigs. The 6.125% Senior Secured Notes are secured by the assets and earnings associated with the ultra-deepwater floater Deepwater Pontus and the equity of the wholly owned subsidiaries that own or operate the collateral rig. Additionally, we were required to deposit $63 million with respect to the 5.875% Senior Secured Notes, and $51 million with respect to the 6.125% Senior Secured Notes, in restricted cash accounts to satisfy debt service and reserve requirements. We are required to pay semiannual installments of principal and interest. We may redeem all or a portion of the 5.875% Senior Secured Notes or the 6.125% Senior Secured Notes on or prior to July 15, 2021 or August 1, 2021, respectively, at a price equal to 100 percent of the aggregate principal amount plus a make-whole provision, and subsequently, at specified redemption prices.

On May 5, 2017, we issued $410 million aggregate principal amount of 5.52% Senior Secured Notes, and we received aggregate cash proceeds of $403 million, net of issue costs. The 5.52% Senior Secured Notes are secured by the assets and earnings associated with the ultra-deepwater floater Deepwater Conqueror, the equity of the wholly owned subsidiaries that own and operate the collateral rig, and certain related assets. We are required to pay quarterly installments of principal and interest on the 5.52% Senior Secured Notes. We may redeem all or a portion of the 5.52% Senior Secured Notes on or prior to December 31, 2021 at a price equal to 100 percent of the aggregate principal amount plus, subject to certain exceptions, a make-whole amount.

At December 31, 2019 and 2018, we had an aggregate amount of $386 million and $347 million, respectively, deposited in restricted cash accounts to satisfy debt service and working capital requirements for the senior secured notes. At December 31, 2019, the aggregate carrying amount of 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, was $6.3 billion. At December 31, 2018, the aggregate carrying amount of rigs encumbered for the senior secured notes, including Deepwater Conqueror, Deepwater Pontus, Deepwater Proteus, Deepwater Thalassa, Transocean Enabler and Transocean Encourage, was $4.4 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 provision, upon the occurrence of certain events related to the respective collateral rigs and the related drilling contracts.

Exchangeable bonds—In connection with the Songa acquisition transactions, we issued $863 million aggregate principal amount of Exchangeable Bonds, as partial consideration for the Songa shares and as consideration for refinancing certain Songa indebtedness. The Exchangeable Bonds may be converted at any time prior to the maturity date at an exchange rate of 97.29756 shares per $1,000 note, equivalent to a conversion price of $10.28 per share, subject to adjustment upon the occurrence of certain events. Holders of Exchangeable Bonds may require us to repurchase all or a portion of such holder’s Exchangeable Bonds upon the occurrence of certain events. The aggregate fair value of the Exchangeable Bonds, measured as of the issuance date, was $1.0 billion, which represented a substantial premium of $172 million above par, and we recorded such premium to additional paid-in capital. We estimated the fair value using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.

Debt assumptions and repayments

In connection with the Songa acquisition, we assumed the rights and obligations under certain credit agreements, a subscription agreement and bond loan agreements. In the year ended December 31, 2018, we made an aggregate cash payment equivalent to $1.65 billion to repay the debt obligations outstanding under these agreements, and we terminated the underlying agreements.

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Debt retirements

Repurchases and repayments—During the three years ended December 31, 2019, we repurchased in the open market debt securities with aggregate principal amounts as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | ​ | 2019 |  | ​ | 2018 |  | ​ | 2017 |
2.50% Senior Notes due October 2017 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 62 | ​
6.00% Senior Notes due March 2018 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 354 | ​
7.375% Senior Notes due April 2018 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 83 | ​
6.50% Senior Notes due November 2020 | ​ | ​ | 23 | ​ | ​ | — | ​ | ​ | 15 | ​
6.375% Senior Notes due December 2021 | ​ | ​ | 43 | ​ | ​ | — | ​ | ​ | 10 | ​
3.80% Senior Notes due October 2022 | ​ | ​ | 32 | ​ | ​ | 95 | ​ | ​ | 33 | ​
9.00% Senior Notes due July 2023 | ​ | ​ | 336 | ​ | ​ | — | ​ | ​ | — | ​
Aggregate principal amount retired | ​ | $ | 434 | ​ | $ | 95 | ​ | $ | 557 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Aggregate cash payment | ​ | $ | 449 | ​ | $ | 95 | ​ | $ | 564 | ​
Aggregate net loss | ​ | $ | (23) | ​ | $ | — | ​ | $ | (7) | ​

​

Tender offers—On February 5, 2019, we completed cash tender offers to purchase up to $700 million aggregate principal amount of certain notes (the “2019 Tendered Notes”). On July 11, 2017, we completed cash tender offers to purchase up to $1.5 billion aggregate principal amount of certain notes (the “2017 Tendered Notes”). During the years ended December 31, 2019 and 2017, we received valid tenders from holders of aggregate principal amounts of the 2019 Tendered Notes and 2017 Tendered Notes as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2019 |  | 2017 | ​
2.50% Senior Notes due October 2017 | ​ | $ | — | ​ | $ | 271 | ​
6.00% Senior Notes due March 2018 | ​ | ​ | — | ​ | ​ | 400 | ​
7.375% Senior Notes due April 2018 | ​ | ​ | — | ​ | ​ | 128 | ​
6.50% Senior Notes due November 2020 | ​ | ​ | 57 | ​ | ​ | 207 | ​
6.375% Senior Notes due December 2021 | ​ | ​ | 63 | ​ | ​ | 213 | ​
3.80% Senior Notes due October 2022 | ​ | ​ | 190 | ​ | ​ | — | ​
9.00% Senior Notes due July 2023 | ​ | ​ | 200 | ​ | ​ | — | ​
Aggregate principal amount retired | ​ | $ | 510 | ​ | $ | 1,219 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Aggregate cash payment | ​ | $ | 522 | ​ | $ | 1,269 | ​
Aggregate net loss | ​ | $ | (18) | ​ | $ | (48) | ​

​

Scheduled maturities and installments—In the years ended December 31, 2019, 2018 and 2017, we made cash payments of $354 million, $257 million and $299 million to repay other indebtedness in scheduled installments. On the scheduled maturity date of October 16, 2017, we made a cash payment of $152 million to repay the outstanding 2.50% senior notes due October 2017, at a price equal to the aggregate principal amount.

Note 11—Derivative Instruments

Forward exchange contracts—At December 31, 2019, we held undesignated forward exchange contracts, extending through March 2020, with an aggregate notional payment amount of $46 million and an aggregate notional receive amount of NOK 405 million, representing a weighted average exchange rate of NOK 8.90 to $1. At December 31, 2018, we held undesignated forward exchange contracts, extending through June 2019, with an aggregate notional payment amount of $76 million and an aggregate notional receive amount of NOK 600 million, representing a weighted average exchange rate of NOK 7.94 to $1. In the years ended December 31, 2019 and 2018, we recognized a loss of $3 million and $10 million, respectively, recorded in other, net, associated with undesignated forward exchange contracts. At December 31, 2019 and 2018, the undesignated forward exchange contracts represented an asset of $1 million and a liability of $6 million, respectively, recorded in other current assets and other current liabilities, respectively.

Currency swaps—In connection with the Songa acquisition, we acquired undesignated currency swaps to receive Norwegian kroner in exchange for paying U.S. dollars at a fixed exchange rate. On the acquisition date, the aggregate fair value of the currency swaps represented a liability of $81 million. In the year ended December 31, 2018, we made an aggregate cash payment of $92 million in connection with the settlement and termination of the currency swaps, and we recognized a loss of $11 million, recorded in other, net.

Interest rate swaps—In connection with the Songa acquisition, we acquired undesignated interest rate swaps, which we repaid in the year ended December 31, 2018. On the acquisition date, the aggregate fair value of the interest rate swaps represented an asset of $14 million. In the year ended December 31, 2018, we received aggregate cash proceeds of $18 million in connection with the settlement and termination of the interest rate swaps, and we recognized a gain of $4 million, recorded in other, net.

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Note 12—Income Taxes

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

Tax provision and rate—Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income. In the years ended December 31, 2019, 2018 and 2017, our effective tax rate was (4.9) percent, (12.8) percent and (3.1) 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, |
​ |  | 2019 |  | 2018 |  | 2017 |
Current tax expense (benefit) |  | $ | (189) | ​ | $ | 244 | ​ | $ | 5 | ​
Deferred tax expense (benefit) | ​ | ​ | 248 | ​ | ​ | (16) | ​ | ​ | 89 | ​
Income tax expense |  | $ | 59 | ​ | $ | 228 | ​ | $ | 94 | ​

​

The following is a reconciliation of the income tax expense (benefit) computed at the Swiss holding company federal statutory rate of 7.83% and our reported provision for income taxes (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
Income tax benefit at Swiss federal statutory rate |  | $ | (94) | ​ | $ | (139) | ​ | $ | (235) | ​
Earnings subject to rates different than the Swiss federal statutory rate | ​ | ​ | 189 | ​ | ​ | (86) | ​ | ​ | (30) | ​
Effect of operating structural changes in the U.S. | ​ | ​ | 98 | ​ | ​ | — | ​ | ​ | — | ​
Changes in valuation allowance | ​ | ​ | 37 | ​ | ​ | 67 | ​ | ​ | 162 | ​
Losses on impairment | ​ | ​ | 35 | ​ | ​ | 114 | ​ | ​ | 241 | ​
Deemed profits taxes | ​ | ​ | 22 | ​ | ​ | 8 | ​ | ​ | 16 | ​
Base erosion and anti-abuse tax | ​ | ​ | 21 | ​ | ​ | 33 | ​ | ​ | — | ​
Withholding taxes | ​ | ​ | 11 | ​ | ​ | 8 | ​ | ​ | 14 | ​
Currency revaluation of Norwegian assets | ​ | ​ | 5 | ​ | ​ | 11 | ​ | ​ | 1 | ​
Effect of U.S. tax reform | ​ | ​ | — | ​ | ​ | 104 | ​ | ​ | 66 | ​
Litigation matters, primarily related to the Macondo well incident | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (70) | ​
Benefit from foreign tax credits | ​ | ​ | (8) | ​ | ​ | (5) | ​ | ​ | (15) | ​
Changes in unrecognized tax benefits, net | ​ | ​ | (268) | ​ | ​ | 117 | ​ | ​ | (56) | ​
Other, net | ​ | ​ | 11 | ​ | ​ | (4) | ​ | ​ | — | ​
Income tax expense |  | $ | 59 | ​ | $ | 228 | ​ | $ | 94 | ​

​

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, |
​ |  | 2019 |  | 2018 |
Deferred tax assets | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net operating loss carryforwards |  | $ | 571 | ​ | $ | 479 | ​
Interest expense limitation | ​ | ​ | 77 | ​ | ​ | 76 | ​
Accrued payroll expenses not currently deductible | ​ | ​ | 45 | ​ | ​ | 49 | ​
Deferred income | ​ | ​ | 41 | ​ | ​ | 26 | ​
Loss contingencies | ​ | ​ | 38 | ​ | ​ | 40 | ​
United Kingdom charter limitation | ​ | ​ | 36 | ​ | ​ | 30 | ​
Tax credit carryforwards | ​ | ​ | 22 | ​ | ​ | 11 | ​
Accrued expenses | ​ | ​ | 16 | ​ | ​ | 44 | ​
Other | ​ | ​ | 24 | ​ | ​ | 13 | ​
Valuation allowance | ​ | ​ | (716) | ​ | ​ | (681) | ​
Total deferred tax assets | ​ | ​ | 154 | ​ | ​ | 87 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deferred tax liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depreciation | ​ | ​ | (361) | ​ | ​ | (62) | ​
Contract intangible amortization | ​ | ​ | (23) | ​ | ​ | (22) | ​
Other | ​ | ​ | (16) | ​ | ​ | (1) | ​
Total deferred tax liabilities | ​ | ​ | (400) | ​ | ​ | (85) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deferred tax assets (liabilities), net |  | $ | (246) | ​ | $ | 2 | ​

​

At December 31, 2019 and 2018, our deferred tax assets included U.S. foreign tax credit carryforwards of $22 million and $11 million, respectively, which will expire between 2020 and 2028. The deferred tax assets related to our net operating losses were generated in various worldwide tax jurisdictions. At December 31, 2019, our net deferred tax assets related to our net operating loss carryforwards included $354 million, which do not expire and $217 million, which will expire beginning between 2020 and 2037. At December 31, 2018, our net deferred tax assets related to our net operating loss carryforwards included $307 million, which do not expire and $172 million, which will expire beginning between 2021 and 2038. In the year ended December 31, 2019, our deferred tax liabilities for depreciation increased primarily as a result of certain operating structural changes that we made in the U.S.

As of December 31, 2019, 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 analyze each jurisdiction separately. We consider objective evidence, such as contract backlog activity, in jurisdictions in which we have profitable contracts. 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, 2019 and 2018, due to uncertainty of realization, we had a valuation allowance of $716 million and $681 million, respectively, on net operating losses and other deferred tax assets.

Our other deferred tax liabilities include taxes related to the earnings of certain subsidiaries, which are not indefinitely reinvested or that will not be indefinitely reinvested in the future. At December 31, 2019, we had $254 million of unremitted earnings which we consider to be indefinitely reinvested. If we were to make a distribution from the unremitted earnings of these subsidiaries, we would be subject to taxes payable of $13 million. If our expectations were to change regarding future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated statement of financial position, results of operations or cash flows.

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, |
​ |  | ​ | 2019 |  | ​ | 2018 |  | ​ | 2017 |
Balance, beginning of period |  | $ | 408 | ​ | $ | 222 | ​ | $ | 274 | ​
Additions for prior year tax positions | ​ | ​ | 6 | ​ | ​ | 172 | ​ | ​ | 17 | ​
Additions for current year tax positions | ​ | ​ | 144 | ​ | ​ | 29 | ​ | ​ | 13 | ​
Reductions related to statute of limitation expirations and changes in law | ​ | ​ | (138) | ​ | ​ | (8) | ​ | ​ | (13) | ​
Reductions for prior year tax positions | ​ | ​ | (66) | ​ | ​ | (7) | ​ | ​ | (68) | ​
Reductions due to settlements | ​ | ​ | (19) | ​ | ​ | — | ​ | ​ | (1) | ​
Balance, end of period |  | $ | 335 | ​ | $ | 408 | ​ | $ | 222 | ​

​

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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, |
​ | ​ | ​ | 2019 |  | ​ | 2018 |
Unrecognized tax benefits, excluding interest and penalties | ​ | $ | 335 | ​ | $ | 408 | ​
Interest and penalties | ​ | ​ | 34 | ​ | ​ | 106 | ​
Unrecognized tax benefits, including interest and penalties | ​ | $ | 369 | ​ | $ | 514 | ​

​

In the years ended December 31, 2019, 2018 and 2017, we recognized, as a component of our income tax provision, income of $72 million, expense of $13 million and income of $9 million, respectively, related to interest and penalties associated with our unrecognized tax benefits. As of December 31, 2019, if recognized, $175 million of our unrecognized tax benefits, including interest and penalties, would favorably impact our effective tax rate. It is reasonably possible that our existing liabilities for unrecognized tax benefits may increase or decrease in the year ending December 31, 2020, 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.

U.S. tax reform—In December 2017, the U.S. enacted the 2017 Tax Act, which introduced changes to U.S. tax law, such as, among others, a transition tax, a federal income tax rate reduction and a base erosion and anti-abuse tax. We recognized the income tax effect of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118, which provides guidance for the application of accounting standards for income taxes in the reporting period in which the 2017 Tax Act was enacted. The one-time transition tax applied to certain unremitted earnings and profits of our non-U.S. subsidiaries that are owned by U.S. subsidiaries. In the year ended December 31, 2018, we completed the evaluation of our unremitted earnings and profits for which the necessary information was not previously available, and we recorded income tax expense of $120 million for estimated transition taxes and $16 million for the utilization of estimated foreign tax credits. In the years ended December 31, 2019 and 2018, we recognized income tax expense of $21 million and $33 million, respectively, related to the bareboat charter structure of our U.S. operations, a significant portion of which is contractually reimbursable by our customers due to a change-in-law provision in certain drilling contracts. In the year ended December 31, 2017, we recognized income tax expense of $66 million with a corresponding decrease to our net deferred tax assets to reflect the reduced federal income tax rate.

Tax returns—We file federal and local tax returns in several jurisdictions throughout the world. With few exceptions, we are no longer subject to examinations of our U.S. and non-U.S. tax matters for years prior to 2011. Our tax returns in the major jurisdictions in which we operate, other than Brazil, as mentioned below, are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in two major jurisdictions for up to 20 years. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the timing or the outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations, although it may have a material adverse effect on our 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 January 25, 2008, we filed a protest letter with the Brazilian tax authorities for these tax assessments, and we are currently engaged in the appeals process. In May 19, 2014, the Brazilian tax authorities issued an additional tax assessment for the years 2009 and 2010, and in June 18, 2014, we filed protests with the Brazilian tax authorities for these tax assessments. During the years ended December 31, 2018 and 2019, a portion of two cases were favorably closed. As of December 31, 2019, the remaining aggregate tax assessment was for BRL 676 million, equivalent to approximately $168 million, including penalties and interest. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. An unfavorable outcome on these proposed assessments could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Other 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. From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities. Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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Table of Contents

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Note 13—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, |
​ | ​ | 2019 | ​ | 2018 | ​ | 2017 |
​ |  | Basic |  | Diluted |  | Basic |  | Diluted |  | Basic |  | Diluted |
Numerator for loss per share | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss attributable to controlling interest | ​ | $ | (1,255) | ​ | $ | (1,255) | ​ | $ | (1,996) | ​ | $ | (1,996) | ​ | $ | (3,127) | ​ | $ | (3,127) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Denominator for loss per share | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted-average shares outstanding | ​ | ​ | 611 | ​ | ​ | 611 | ​ | ​ | 467 | ​ | ​ | 467 | ​ | ​ | 391 | ​ | ​ | 391 | ​
Effect of share-based awards and other equity instruments | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | — | ​ | ​ | — | ​
Weighted-average shares for per share calculation | ​ | ​ | 612 | ​ | ​ | 612 | ​ | ​ | 468 | ​ | ​ | 468 | ​ | ​ | 391 | ​ | ​ | 391 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Loss per share | ​ | $ | (2.05) | ​ | $ | (2.05) | ​ | $ | (4.27) | ​ | $ | (4.27) | ​ | $ | (8.00) | ​ | $ | (8.00) | ​

​

In the years ended December 31, 2019, 2018 and 2017, we excluded from the calculation 12.0 million, 10.6 million and 4.7 million share-based awards, respectively, since the effect would have been anti-dilutive. In the years ended December 31, 2019 and 2018, we excluded from the calculation 84.0 million and 77.2 million shares, respectively, issuable upon conversion of the Exchangeable Bonds since the effect would have been anti-dilutive.

Note 14—Postemployment Benefit Plans

Defined benefit pension and other postemployment benefit plans

Overview—As of December 31, 2019 we had defined benefit plans in the U.S., the United Kingdom (“U.K.”), and Norway. As of December 31, 2019, in the U.S., we had three funded and three unfunded defined benefit plans (the “U.S. Plans”). As of December 31, 2019, in the U.K., we had one funded defined benefit plan (the “U.K. Plan”). As of December 31, 2019, in Norway, we had four funded and two unfunded defined benefit plans (the “Norway Plans”), all of which were group pension schemes with life insurance companies. We refer to the U.K. Plan and the Norway Plans, collectively, as the “Non-U.S. Plans.” We refer to the U.S. Plans and the Non-U.S. Plans, collectively, as the “Transocean Plans”. Additionally, we 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. Benefits under the U.S. Plans and the U.K. Plan have ceased accruing. We maintain the respective pension obligations under such plans until they have been fully satisfied.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |
Discount rate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | 3.27 | % | 2.13 | % | 2.39 | % | 4.31 | % | 2.86 | % | 3.56 | %
Compensation trend rate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | na | ​ | 2.25 | % | na | ​ | na | ​ | 2.75 | % | na | ​

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2019 | ​ | Year ended December 31, 2018 | ​ | Year ended December 31, 2017 |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | U.S. | ​ | Non-U.S. |  | ​ | ​
​ |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | OPEB Plans | ​
Discount rate | ​ | 4.32 | % | 2.86 | % | 3.56 | % | 3.68 | % | 2.49 | % | 2.93 | % | 4.26 | % | 2.69 | % | 3.08 | %
Expected rate of return | ​ | 6.20 | % | 4.39 | % | na | ​ | 6.21 | % | 4.72 | % | na | ​ | 6.31 | % | 4.79 | % | na | ​
Compensation trend rate | ​ | na | ​ | 2.75 | % | na | ​ | na | ​ | 2.50 | % | na | ​ | na | ​ | 2.25 | % | na | ​

“na” means not applicable.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended December 31, 2019 | ​ | Year ended December 31, 2018 | ​ | Year ended December 31, 2017 |
​ | ​ | 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 | ​ | $ | — | ​ | $ | 7 | ​ | $ | — | ​ | $ | 7 | ​ | $ | — | ​ | $ | 7 | ​ | $ | — | ​ | $ | 7 | ​ | $ | 3 | ​ | $ | 3 | ​ | $ | — | ​ | $ | 6 | ​
Interest cost | ​ | ​ | 63 | ​ | ​ | 10 | ​ | ​ | 1 | ​ | ​ | 74 | ​ | ​ | 61 | ​ | ​ | 10 | ​ | ​ | 1 | ​ | ​ | 72 | ​ | ​ | 65 | ​ | ​ | 11 | ​ | ​ | — | ​ | ​ | 76 | ​
Expected return on plan assets | ​ | ​ | (71) | ​ | ​ | (17) | ​ | ​ | — | ​ | ​ | (88) | ​ | ​ | (72) | ​ | ​ | (19) | ​ | ​ | — | ​ | ​ | (91) | ​ | ​ | (74) | ​ | ​ | (20) | ​ | ​ | — | ​ | ​ | (94) | ​
Special termination benefits | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​
Settlements and curtailments | ​ | ​ | 1 | ​ | ​ | 2 | ​ | ​ | — | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | (1) | ​ | ​ | (4) | ​ | ​ | (5) | ​ | ​ | — | ​ | ​ | 13 | ​ | ​ | — | ​ | ​ | 13 | ​
Actuarial loss, net | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 3 | ​ | ​ | 8 | ​ | ​ | 1 | ​ | ​ | — | ​ | ​ | 9 | ​ | ​ | 5 | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | 7 | ​
Prior service gain, net | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (2) | ​ | ​ | (2) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (2) | ​ | ​ | (2) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (3) | ​ | ​ | (3) | ​
Net periodic benefit costs (income) | ​ | $ | (4) | ​ | $ | 2 | ​ | $ | (1) | ​ | $ | (3) | ​ | $ | (3) | ​ | $ | (2) | ​ | $ | (4) | ​ | $ | (9) | ​ | $ | (1) | ​ | $ | 8 | ​ | $ | (2) | ​ | $ | 5 | ​

​

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Table of Contents

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Funded status—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, 2019 | ​ | Year ended December 31, 2018 |
​ | ​ | 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 |  | $ | 1,527 | ​ | $ | 338 | ​ | $ | 17 | ​ | $ | 1,882 | ​ | $ | 1,680 | ​ | $ | 379 | ​ | $ | 19 | ​ | $ | 2,078 | ​
Assumed projected benefit obligation | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 29 | ​ | ​ | — | ​ | ​ | 29 | ​
Actuarial (gains) losses, net | ​ | ​ | 202 | ​ | ​ | 45 | ​ | ​ | 1 | ​ | ​ | 248 | ​ | ​ | (145) | ​ | ​ | (45) | ​ | ​ | (2) | ​ | ​ | (192) | ​
Service cost | ​ | ​ | — | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | 7 | ​
Interest cost | ​ | ​ | 63 | ​ | ​ | 10 | ​ | ​ | 1 | ​ | ​ | 74 | ​ | ​ | 61 | ​ | ​ | 10 | ​ | ​ | 1 | ​ | ​ | 72 | ​
Currency exchange rate changes | ​ | ​ | — | ​ | ​ | 14 | ​ | ​ | — | ​ | ​ | 14 | ​ | ​ | — | ​ | ​ | (21) | ​ | ​ | — | ​ | ​ | (21) | ​
Benefits paid | ​ | ​ | (72) | ​ | ​ | (19) | ​ | ​ | (2) | ​ | ​ | (93) | ​ | ​ | (69) | ​ | ​ | (19) | ​ | ​ | (2) | ​ | ​ | (90) | ​
Settlements | ​ | ​ | (24) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (24) | ​ | ​ | — | ​ | ​ | (3) | ​ | ​ | — | ​ | ​ | (3) | ​
Plan amendment | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1 | ​ | ​ | — | ​ | ​ | 1 | ​
Special termination benefit | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1 | ​ | ​ | 1 | ​
Projected benefit obligation, end of period | ​ | ​ | 1,696 | ​ | ​ | 395 | ​ | ​ | 17 | ​ | ​ | 2,108 | ​ | ​ | 1,527 | ​ | ​ | 338 | ​ | ​ | 17 | ​ | ​ | 1,882 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in plan assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fair value of plan assets, beginning of period | ​ | ​ | 1,189 | ​ | ​ | 378 | ​ | ​ | — | ​ | ​ | 1,567 | ​ | ​ | 1,343 | ​ | ​ | 393 | ​ | ​ | — | ​ | ​ | 1,736 | ​
Fair value of acquired plan assets | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 22 | ​ | ​ | — | ​ | ​ | 22 | ​
Actual return on plan assets | ​ | ​ | 272 | ​ | ​ | 39 | ​ | ​ | — | ​ | ​ | 311 | ​ | ​ | (87) | ​ | ​ | (6) | ​ | ​ | — | ​ | ​ | (93) | ​
Currency exchange rate changes | ​ | ​ | — | ​ | ​ | 16 | ​ | ​ | — | ​ | ​ | 16 | ​ | ​ | — | ​ | ​ | (22) | ​ | ​ | — | ​ | ​ | (22) | ​
Employer contributions | ​ | ​ | 4 | ​ | ​ | 16 | ​ | ​ | 2 | ​ | ​ | 22 | ​ | ​ | 2 | ​ | ​ | 13 | ​ | ​ | 2 | ​ | ​ | 17 | ​
Benefits paid | ​ | ​ | (72) | ​ | ​ | (19) | ​ | ​ | (2) | ​ | ​ | (93) | ​ | ​ | (69) | ​ | ​ | (19) | ​ | ​ | (2) | ​ | ​ | (90) | ​
Settlements | ​ | ​ | (24) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (24) | ​ | ​ | — | ​ | ​ | (3) | ​ | ​ | — | ​ | ​ | (3) | ​
Fair value of plan assets, end of period | ​ | ​ | 1,369 | ​ | ​ | 430 | ​ | ​ | — | ​ | ​ | 1,799 | ​ | ​ | 1,189 | ​ | ​ | 378 | ​ | ​ | — | ​ | ​ | 1,567 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Funded status, end of period |  | $ | (327) | ​ | $ | 35 | ​ | $ | (17) | ​ | $ | (309) | ​ | $ | (338) | ​ | $ | 40 | ​ | $ | (17) | ​ | $ | (315) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance sheet classification, end of period: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Pension asset, non-current |  | $ | — | ​ | $ | 42 | ​ | $ | — | ​ | $ | 42 | ​ | $ | — | ​ | $ | 47 | ​ | $ | — | ​ | $ | 47 | ​
Pension liability, current | ​ | ​ | (1) | ​ | ​ | (1) | ​ | ​ | (3) | ​ | ​ | (5) | ​ | ​ | (3) | ​ | ​ | (1) | ​ | ​ | (3) | ​ | ​ | (7) | ​
Pension liability, non-current | ​ | ​ | (326) | ​ | ​ | (6) | ​ | ​ | (14) | ​ | ​ | (346) | ​ | ​ | (335) | ​ | ​ | (6) | ​ | ​ | (14) | ​ | ​ | (355) | ​
Accumulated other comprehensive loss (income), before taxes | ​ | ​ | 304 | ​ | ​ | 84 | ​ | ​ | (12) | ​ | ​ | 376 | ​ | ​ | 307 | ​ | ​ | 64 | ​ | ​ | (15) | ​ | ​ | 356 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accumulated benefit obligation, end of period | ​ | $ | 1,696 | ​ | $ | 385 | ​ | $ | 17 | ​ | $ | 2,098 | ​ | $ | 1,527 | ​ | $ | 328 | ​ | $ | 17 | ​ | $ | 1,872 | ​

​

The aggregate projected benefit obligation and fair value of plan assets for plans with a projected benefit obligation in excess of plan assets were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ |
​ |  | Plans |  | Plans |  | Plans |  | Total |  | Plans |  | Plans |  | Plans |  | Total |
Projected benefit obligation |  | $ | 1,696 | ​ | $ | 56 | ​ | $ | 17 | ​ | $ | 1,769 | ​ | $ | 1,527 | ​ | $ | 26 | ​ | $ | 17 | ​ | $ | 1,570 | ​
Fair value of plan assets | ​ | ​ | 1,369 | ​ | ​ | 49 | ​ | ​ | — | ​ | ​ | 1,418 | ​ | ​ | 1,189 | ​ | ​ | 20 | ​ | ​ | — | ​ | ​ | 1,209 | ​

​

The aggregate accumulated benefit obligation and fair value of plan assets for plans with an accumulated benefit obligation in excess of plan assets were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ |
​ |  | Plans |  | Plans |  | Plans |  | Total |  | Plans |  | Plans |  | Plans |  | Total |
Accumulated benefit obligation |  | $ | 1,696 | ​ | $ | 1 | ​ | $ | 17 | ​ | $ | 1,714 | ​ | $ | 1,527 | ​ | $ | 3 | ​ | $ | 17 | ​ | $ | 1,547 | ​
Fair value of plan assets | ​ | ​ | 1,369 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,369 | ​ | ​ | 1,189 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,189 | ​

​

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ |
​ |  | Plans |  | Plans |  | Plans |  | Total |  | Plans |  | Plans |  | Plans |  | Total |
Actuarial loss, net |  | $ | 304 | ​ | $ | 84 | ​ | $ | 2 | ​ | $ | 390 | ​ | $ | 307 | ​ | $ | 63 | ​ | $ | 1 | ​ | $ | 371 | ​
Prior service cost, net | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (14) | ​ | ​ | (14) | ​ | ​ | — | ​ | ​ | 1 | ​ | ​ | (16) | ​ | ​ | (15) | ​
Accumulated other comprehensive loss (income), before taxes |  | $ | 304 | ​ | $ | 84 | ​ | $ | (12) | ​ | $ | 376 | ​ | $ | 307 | ​ | $ | 64 | ​ | $ | (15) | ​ | $ | 356 | ​

​

The amounts in accumulated other comprehensive loss (income) expected to be recognized as components of net periodic benefit costs are as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Year ending December 31, 2020 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | Plans |  | Plans |  | Plans |  | Total |
Actuarial loss, net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | $ | 9 | ​ | $ | 1 | ​ | $ | — | ​ | $ | 10 | ​
Prior service cost, net | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (2) | ​ | ​ | (2) | ​
Total amount expected to be recognized | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | $ | 9 | ​ | $ | 1 | ​ | $ | (2) | ​ | $ | 8 | ​

​

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Table of Contents

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Plan assets—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. For the Norway Plans, we establish minimum rates of return under the terms of investment contracts with insurance companies. The weighted-average target and actual allocations of the investments for the funded Transocean Plans were as follows:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | Target allocation | ​ | Actual allocation | ​ | Target allocation | ​ | Actual allocation |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | U.S. | ​ | Non-U.S. | ​ | U.S. | ​ | Non-U.S. | ​ | U.S. | ​ | Non-U.S. |
​ |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |
Equity securities | ​ | 50 | % | 24 | % | 51 | % | 27 | % | 50 | % | 34 | % | 50 | % | 32 | %
Fixed income securities | ​ | 50 | % | 60 | % | 49 | % | 56 | % | 50 | % | 51 | % | 50 | % | 52 | %
Other investments | ​ | — | % | 16 | % | — | % | 17 | % | — | ​ | 15 | % | — | ​ | 16 | %
Total | ​ | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | %

The investments for the funded Transocean Plans were categorized as follows (in millions):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2019 |
​ | ​ | Significant observable inputs | ​ | Significant other observable inputs | ​ | Total |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean |
​ |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |
Mutual funds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
U.S. equity funds |  | $ | 480 | ​ | $ | — | ​ | $ | 480 | ​ | $ | 1 | ​ | $ | — | ​ | $ | 1 | ​ | $ | 481 | ​ | $ | — | ​ | $ | 481 | ​
Non-U.S. equity funds | ​ | ​ | 216 | ​ | ​ | — | ​ | ​ | 216 | ​ | ​ | 5 | ​ | ​ | 115 | ​ | ​ | 120 | ​ | ​ | 221 | ​ | ​ | 115 | ​ | ​ | 336 | ​
Bond funds | ​ | ​ | 656 | ​ | ​ | — | ​ | ​ | 656 | ​ | ​ | 6 | ​ | ​ | 240 | ​ | ​ | 246 | ​ | ​ | 662 | ​ | ​ | 240 | ​ | ​ | 902 | ​
Total mutual funds | ​ | ​ | 1,352 | ​ | ​ | — | ​ | ​ | 1,352 | ​ | ​ | 12 | ​ | ​ | 355 | ​ | ​ | 367 | ​ | ​ | 1,364 | ​ | ​ | 355 | ​ | ​ | 1,719 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and money market funds | ​ | ​ | 5 | ​ | ​ | 4 | ​ | ​ | 9 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5 | ​ | ​ | 4 | ​ | ​ | 9 | ​
Property collective trusts | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 20 | ​ | ​ | 20 | ​ | ​ | — | ​ | ​ | 20 | ​ | ​ | 20 | ​
Investment contracts | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 51 | ​ | ​ | 51 | ​ | ​ | — | ​ | ​ | 51 | ​ | ​ | 51 | ​
Total other investments | ​ | ​ | 5 | ​ | ​ | 4 | ​ | ​ | 9 | ​ | ​ | — | ​ | ​ | 71 | ​ | ​ | 71 | ​ | ​ | 5 | ​ | ​ | 75 | ​ | ​ | 80 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total investments |  | $ | 1,357 | ​ | $ | 4 | ​ | $ | 1,361 | ​ | $ | 12 | ​ | $ | 426 | ​ | $ | 438 | ​ | $ | 1,369 | ​ | $ | 430 | ​ | $ | 1,799 | ​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2018 |
​ | ​ | Significant observable inputs | ​ | Significant other observable inputs | ​ | Total |
​ | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean | ​ | U.S. | ​ | Non-U.S. | ​ | Transocean |
​ |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |  | Plans |
Mutual funds | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
U.S. equity funds |  | $ | 401 | ​ | $ | — | ​ | $ | 401 | ​ | $ | — | ​ | $ | — | ​ | $ | — | ​ | $ | 401 | ​ | $ | — | ​ | $ | 401 | ​
Non-U.S. equity funds | ​ | ​ | 179 | ​ | ​ | — | ​ | ​ | 179 | ​ | ​ | 5 | ​ | ​ | 120 | ​ | ​ | 125 | ​ | ​ | 184 | ​ | ​ | 120 | ​ | ​ | 304 | ​
Bond funds | ​ | ​ | 591 | ​ | ​ | — | ​ | ​ | 591 | ​ | ​ | 7 | ​ | ​ | 195 | ​ | ​ | 202 | ​ | ​ | 598 | ​ | ​ | 195 | ​ | ​ | 793 | ​
Total mutual funds | ​ | ​ | 1,171 | ​ | ​ | — | ​ | ​ | 1,171 | ​ | ​ | 12 | ​ | ​ | 315 | ​ | ​ | 327 | ​ | ​ | 1,183 | ​ | ​ | 315 | ​ | ​ | 1,498 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other investments | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and money market funds | ​ | ​ | 6 | ​ | ​ | 1 | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6 | ​ | ​ | 1 | ​ | ​ | 7 | ​
Property collective trusts | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 19 | ​ | ​ | 19 | ​ | ​ | — | ​ | ​ | 19 | ​ | ​ | 19 | ​
Investment contracts | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 43 | ​ | ​ | 43 | ​ | ​ | — | ​ | ​ | 43 | ​ | ​ | 43 | ​
Total other investments | ​ | ​ | 6 | ​ | ​ | 1 | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | 62 | ​ | ​ | 62 | ​ | ​ | 6 | ​ | ​ | 63 | ​ | ​ | 69 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total investments |  | $ | 1,177 | ​ | $ | 1 | ​ | $ | 1,178 | ​ | $ | 12 | ​ | $ | 377 | ​ | $ | 389 | ​ | $ | 1,189 | ​ | $ | 378 | ​ | $ | 1,567 | ​

​

The U.S. Plans and the U.K. Plan invest primarily in passively managed funds that reference market indices. The funded Norway Plans are subject to contractual terms under selected insurance programs. Each plan’s 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. As the 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.

Funding contributions—In the years ended December 31, 2019, 2018 and 2017, we made an aggregate contribution of $22 million, $17 million and $15 million, respectively, to the Transocean Plans and the OPEB Plans using our cash flows from operations. In the year ending December 31, 2020, we expect to contribute $18 million to the Transocean Plans, and we expect to fund benefit payments of approximately $3 million for the OPEB Plans as costs are incurred.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | U.S. | ​ | Non-U.S. | ​ | OPEB | ​ | ​ | ​ |
​ |  | Plans |  | Plans |  | Plans |  | Total |
Years ending December 31, | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2020 |  | $ | 79 | ​ | $ | 8 | ​ | $ | 3 | ​ | $ | 90 | ​
2021 | ​ | ​ | 79 | ​ | ​ | 8 | ​ | ​ | 3 | ​ | ​ | 90 | ​
2022 | ​ | ​ | 81 | ​ | ​ | 8 | ​ | ​ | 3 | ​ | ​ | 92 | ​
2023 | ​ | ​ | 82 | ​ | ​ | 9 | ​ | ​ | 2 | ​ | ​ | 93 | ​
2024 | ​ | ​ | 82 | ​ | ​ | 10 | ​ | ​ | 3 | ​ | ​ | 95 | ​
2025 - 2029 | ​ | ​ | 419 | ​ | ​ | 59 | ​ | ​ | 3 | ​ | ​ | 481 | ​

​

Defined contribution plans

We sponsor defined contribution plans, for our employees, the most significant of which were as follows: (1) a qualified savings plan covering certain employees working in the U.S., (2) a non-qualified supplemental plan covering certain eligible employees working in the U.S., (3) a qualified savings plan covering certain eligible U.K. employees, (4) a non-qualified savings plan covering certain employees working outside the U.S. and U.K. and (5) various savings plans covering eligible employees working in Norway. In the years ended December 31, 2019, 2018 and 2017, we recognized expense of $52 million, $50 million and $43 million, respectively, related to our defined contribution plans.

Note 15—Commitments and Contingencies

Purchase and service agreement obligations

We have purchase obligations with shipyards and other contractors 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 control 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, 2019, 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, | ​ | ​ | ​ | ​ | ​ | ​
2020 |  | $ | 1,067 | ​ | $ | 110
2021 | ​ | ​ | 49 | ​ | ​ | 117
2022 | ​ | ​ | — | ​ | ​ | 120
2023 | ​ | ​ | — | ​ | ​ | 124
2024 | ​ | ​ | — | ​ | ​ | 129
Thereafter | ​ | ​ | — | ​ | ​ | 435
Total |  | $ | 1,116 | ​ | $ | 1,035

​

Letters of credit and surety bonds

At December 31, 2019 and 2018, we had outstanding letters of credit totaling $19 million and $31 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, 2019 and 2018, we also had outstanding surety bonds totaling $113 million and $84 million, respectively, to secure customs obligations related to the importation of our rigs and certain performance and other obligations. At December 31, 2019 and 2018, the aggregate cash collateral held by institutions to secure our letters of credit and surety bonds was $10 million and $5 million, respectively.

Legal proceedings

Macondo well incident—On April 22, 2010, the ultra-deepwater floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig off the coast of Louisiana. At the time of the explosion, Deepwater Horizon was contracted to an affiliate of BP plc. Litigation, including civil and criminal claims, commenced shortly after the incident, and most claims against us were consolidated by the U.S. Judicial Panel on Multidistrict Litigation and transferred to the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”), a significant portion of which has now been resolved or is pending release of funds from escrow. We will vigorously defend against any actions not resolved by our previous settlements and pursue any and all defenses available.

At December 31, 2019 and 2018, the remaining liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $124 million and $158 million, respectively, recorded in other current liabilities, the majority of which is related to the settlement agreement that we and the Plaintiff Steering Committee filed with the MDL Court in May 2015 (the “PSC Settlement Agreement”). On February 15, 2017, the MDL Court entered a final order and judgment approving the PSC Settlement Agreement. Through the PSC Settlement Agreement, we agreed to pay a total of $212 million to be allocated between two classes of

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plaintiffs in exchange for a release of all respective claims each class has against us. As required under the PSC Settlement Agreement, we deposited the settlement amount into an escrow account established by the MDL Court. In August 2019 and November 2018, the MDL Court released $33 million and $58 million, respectively, from the escrow account to make payments to the plaintiffs. At December 31, 2019 and 2018, the remaining cash balance in the escrow account was $125 million and $156 million, respectively, recorded in restricted cash accounts and investments.

Nigerian Cabotage Act litigation—In October 2007, three of our subsidiaries were each served a Notice and Demand from the Nigeria Maritime Administration and Safety Agency (“NIMASA”), imposing a two percent surcharge on the value of all contracts performed by us in Nigeria pursuant to the Coastal and Inland Shipping (Cabotage) Act 2003 (the “Cabotage Act”). Our subsidiaries each filed an originating summons in the Federal High Court in Lagos challenging the imposition of this surcharge on the basis that the Cabotage Act and associated levy is not applicable to drilling rigs. The respondents challenged the competence of the suits on several procedural grounds. The court upheld the objections and dismissed the suits. In December 2010, our subsidiaries filed a new joint Cabotage Act suit. In June 2019, the Court of Appeal of Nigeria ruled the suits had been properly dismissed, confirming that offshore drilling rigs are not subject to the surcharges of the Cabotage Act. NIMASA has not appealed this ruling, and the deadline for appeal has passed. While we cannot provide assurance that NIMASA will not attempt to challenge the ruling in the future, we do not expect the proceedings to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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. At December 31, 2019, nine plaintiffs have claims pending in Louisiana, 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.

One of our subsidiaries has been 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, 2019, the subsidiary was a defendant in approximately 185 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 September 2018, the subsidiary and certain insurers agreed to a settlement of outstanding disputes that leaves the subsidiary with funding, including cash, annuities and coverage in place settlement, that we believe will be sufficient 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.

Other matters—We are involved in various tax matters, 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.

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Nevertheless, based on available information, we do not expect the ultimate liability, if any, resulting from all environmental matters, including the liability for all related pending legal proceedings, asserted legal claims, the potential claims in Alhambra, California, for which tests detected no contaminants, and known potential legal claims that are likely to be asserted, to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Note 16—Equity

Shares held by subsidiaries—One of our subsidiaries holds our shares for future use to satisfy our obligations to deliver shares in connection with awards granted under our incentive plans or other rights to acquire our shares. At December 31, 2019 and 2018, our subsidiary held 6.1 million and 0.9 million shares, respectively.

Accumulated other comprehensive loss—The changes in accumulated other comprehensive loss, presented net of tax, for our defined benefit pension plans were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, | ​
​ |  | 2019 |  | 2018 |
Balance, beginning of period |  | $ | (279) | ​ | $ | (290) | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other comprehensive income (loss) before reclassifications | ​ | ​ | (25) | ​ | ​ | 6 | ​
Reclassifications to net loss | ​ | ​ | 4 | ​ | ​ | 5 | ​
Other comprehensive income (loss), net | ​ | ​ | (21) | ​ | ​ | 11 | ​
Effect of adopting accounting standards update | ​ | ​ | (24) | ​ | ​ | — | ​
Balance, end of period |  | $ | (324) | ​ | $ | (279) | ​

​

Redeemable noncontrolling interest—Until June 11, 2018, we owned a 65 percent interest in Angola Deepwater Drilling Company Ltd. (“ADDCL”), a Cayman Islands company and variable interest entity for which we concluded that we were the primary beneficiary. Angco Cayman Limited (“Angco Cayman”) owned the remaining a 35 percent interest in ADDCL. Under the terms of ADDCL’s governing documents, Angco Cayman had the right to require us to purchase its interest in ADDCL for cash, and accordingly, we presented the carrying amount of Angco Cayman’s ownership interest as redeemable noncontrolling interest on our consolidated balance sheets. We also had the right under ADDCL’s governing documents to require Angco Cayman to sell us its interest, and we exercised that right. On June 11, 2018, pursuant to a settlement requiring no cash payment, we acquired the interests in ADDCL not previously owned by us, and ADDCL became our wholly owned subsidiary. In connection with the acquisition, we reclassified the $53 million aggregate carrying amount of the redeemable noncontrolling interest to additional paid-in capital.

Note 17—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. Our 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, 2019, we had 32.7 million shares authorized and 7.4 million shares available to be granted under the Long-Term Incentive Plan. At December 31, 2019, the total unrecognized compensation cost related to our unvested share-based awards was $42 million, which is expected to be recognized over a weighted-average period of 1.7 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. Performance awards typically are subject to a three-year measurement period during which the number of options or shares to be issued remains uncertain until the end of the measurement period, at which time the awarded number of options or shares to be issued is determined. The performance awards typically vest in one aggregate installment following the determination date. Stock options are subject to a stated vesting period and, once vested, typically have a seven-year term during which they are exercisable.

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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 for service-based units granted under our incentive plans during the year ended December 31, 2019:

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Number | ​ | Weighted-average |
​ | ​ | of | ​ | grant-date fair value |
​ |  | units |  | per unit |
Unvested at January 1, 2019 | ​ | 4,077,992 | ​ | $ | 10.40 |
Granted | ​ | 3,044,494 | ​ | ​ | 8.33 | ​
Vested | ​ | (2,224,030) | ​ | ​ | 10.40 | ​
Forfeited | ​ | (178,878) | ​ | ​ | 9.01 | ​
Unvested at December 31, 2019 | ​ | 4,719,578 | ​ | $ | 9.11 | ​

​

During the year ended December 31, 2019, the vested restricted share units had an aggregate grant-date fair value of $23 million. During the years ended December 31, 2018 and 2017, we granted 2,521,939 and 1,921,029 service-based units, respectively, with a per unit weighted-average grant-date fair value of $9.67 and $13.03, respectively. During the years ended December 31, 2018 and 2017, we had 2,087,141 and 1,867,970 service-based units, respectively, that vested with an aggregate grant-date fair value of $27 million and $28 million, respectively.

Stock options—The following table summarizes activity for vested and unvested service-based stock options outstanding under our incentive plans during the year ended December 31, 2019:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | 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, 2019 | ​ | 3,767,483 | ​ | $ | 21.56 | ​ | 6.84 | ​ | $ | — | ​
Granted | ​ | 1,594,528 | ​ | ​ | 8.35 | ​ | — | ​ | ​ | — | ​
Forfeited | ​ | (201,596) | ​ | ​ | 30.93 | ​ | — | ​ | ​ | — | ​
Expired | ​ | (295,990) | ​ | ​ | 60.33 | ​ | — | ​ | ​ | — | ​
Outstanding at December 31, 2019 | ​ | 4,864,425 | ​ | $ | 14.48 | ​ | 7.34 | ​ | $ | — | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Vested and exercisable at December 31, 2019 | ​ | 2,212,911 | ​ | $ | 20.88 | ​ | 5.85 | ​ | $ | — | ​

​

During the year ended December 31, 2019, the granted stock options had a per option weighted-average grant-date fair value of $4.09. During the year ended December 31, 2019, the vested stock options had an aggregate grant-date fair value of $10 million. At December 31, 2019 and 2018, there were outstanding unvested stock options to purchase 2,651,514 and 2,166,969 shares, respectively. During the years ended December 31, 2018 and 2017, we granted stock options to purchase 1,249,266 and 877,231 shares, respectively, with a per option weighted-average grant-date fair value of $9.18 and $6.46, respectively. During the years ended December 31, 2018 and 2017, the vested stock options had an aggregate grant-date fair value of $6 million and $2 million, respectively. During the years ended December 31, 2017 and 2016, no stock options were exercised.

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. The number of shares ultimately earned per unit is quantified upon completion of the specified period at the determination date. The following table summarizes unvested activity for performance-based units under our incentive plans during the year ended December 31, 2019:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Number | ​ | Weighted-average |
​ | ​ | ​ | ​ | ​ | ​ | ​ | of | ​ | grant-date fair value |
​ |  | ​ | ​ | ​ | ​ | ​ | units |  | per unit |
Unvested at January 1, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | 1,763,794 | ​ | $ | 12.93 | ​
Granted | ​ | ​ | ​ | ​ | ​ | ​ | 1,067,316 | ​ | ​ | 10.77 | ​
Vested | ​ | ​ | ​ | ​ | ​ | ​ | (676,098) | ​ | ​ | 16.25 | ​
Forfeited | ​ | ​ | ​ | ​ | ​ | ​ | (73,393) | ​ | ​ | 3.02 | ​
Unvested at December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | 2,081,619 | ​ | $ | 10.78 | ​

​

During the year ended December 31, 2019, the vested performance-based units had an aggregate grant-date fair value of $11 million. During the years ended December 31, 2018 and 2017, we granted 1,074,054 and 689,740 performance-based units, respectively, with a per unit weighted-average grant-date fair value of $10.79 and $16.25, respectively. During the years ended December 31, 2018 and 2017, the vested performance-based units had an aggregate grant-date fair value of $11 million and $7 million, respectively.

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Note 18—Supplemental Balance Sheet Information

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, |
​ |  | 2019 |  | 2018 |
Other current liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accrued payroll and employee benefits |  | $ | 207 | ​ | $ | 182 | ​
Accrued interest | ​ | ​ | 169 | ​ | ​ | 184 | ​
Accrued taxes, other than income | ​ | ​ | 73 | ​ | ​ | 69 | ​
Finance lease liability | ​ | ​ | 35 | ​ | ​ | — | ​
Operating lease liabilities | ​ | ​ | 13 | ​ | ​ | — | ​
Deferred revenues | ​ | ​ | 100 | ​ | ​ | 87 | ​
Contingent liabilities | ​ | ​ | 180 | ​ | ​ | 213 | ​
Other | ​ | ​ | 4 | ​ | ​ | 11 | ​
Total other current liabilities |  | $ | 781 | ​ | $ | 746 | ​

​

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, |
​ |  | 2019 |  | 2018 |
Other long-term liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​
Postemployment benefit plan obligations |  | $ | 346 | ​ | $ | 355 | ​
Finance lease liability | ​ | ​ | 444 | ​ | ​ | — | ​
Operating lease liabilities | ​ | ​ | 116 | ​ | ​ | — | ​
Income taxes payable | ​ | ​ | 179 | ​ | ​ | 476 | ​
Deferred revenues | ​ | ​ | 429 | ​ | ​ | 399 | ​
Construction contract intangible liability | ​ | ​ | — | ​ | ​ | 132 | ​
Other | ​ | ​ | 41 | ​ | ​ | 62 | ​
Total other long-term liabilities |  | $ | 1,555 | ​ | $ | 1,424 | ​

​

​

Note 19—Supplemental Cash Flow Information

Net cash provided by operating activities attributable to the net change in other operating assets and liabilities was comprised of the following (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
Changes in other operating assets and liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Decrease in accounts receivable |  | $ | 87 | ​ | $ | 180 | ​ | $ | 230 | ​
(Increase) decrease in other assets | ​ | ​ | (30) | ​ | ​ | 3 | ​ | ​ | (37) | ​
Decrease in accounts payable and other current liabilities | ​ | ​ | (21) | ​ | ​ | (154) | ​ | ​ | (115) | ​
(Decrease) increase in other long-term liabilities | ​ | ​ | (34) | ​ | ​ | 80 | ​ | ​ | (13) | ​
Change in income taxes receivable / payable, net | ​ | ​ | (303) | ​ | ​ | 125 | ​ | ​ | (58) | ​
Change in receivables from / payables to affiliates, net | ​ | ​ | (10) | ​ | ​ | — | ​ | ​ | — | ​
​ |  | $ | (311) | ​ | $ | 234 | ​ | $ | 7 | ​

​

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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, |
​ |  | 2019 |  | 2018 |  | 2017 |
Certain cash operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash payments for interest |  | $ | 648 | ​ | $ | 570 | ​ | $ | 486 | ​
Cash payments for income taxes | ​ | ​ | 121 | ​ | ​ | 151 | ​ | ​ | 124 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-cash investing and financing activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Capital additions, accrued at end of period (a) | ​ | $ | 48 | ​ | $ | 30 | ​ | $ | 20 | ​
Issuance of shares in business combinations (b) | ​ | ​ | — | ​ | ​ | 2,112 | ​ | ​ | — | ​
Issuance of debt in business combination (c) | ​ | ​ | — | ​ | ​ | 1,026 | ​ | ​ | — | ​

| (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—Drilling Fleet. |

| (b) | In connection with our acquisition of Songa and Ocean Rig, we issued 66.9 million and 147.7 million shares, respectively, with an aggregate fair value of $735 million and $1.4 billion, respectively. See Note 4—Business Combinations. |

| (c) | In connection with our acquisition of Songa, we issued $854 million aggregate principal amount of Exchangeable Bonds as partial consideration to Songa shareholders and settlement for certain Songa indebtedness. See Note 4—Business Combinations. |

Note 20—Financial Instruments

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2019 | ​ | December 31, 2018 |
​ | ​ | Carrying | ​ | Fair | ​ | Carrying | ​ | Fair |
​ |  | amount |  | value |  | amount |  | value |
Cash and cash equivalents |  | $ | 1,790 | ​ | $ | 1,790 | ​ | $ | 2,160 | ​ | $ | 2,160 | ​
Restricted cash and cash equivalents | ​ | ​ | 558 | ​ | ​ | 558 | ​ | ​ | 429 | ​ | ​ | 429 | ​
Restricted investments | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 123 | ​ | ​ | 123 | ​
Long-term debt, including current maturities | ​ | ​ | 9,261 | ​ | ​ | 8,976 | ​ | ​ | 9,978 | ​ | ​ | 9,212 | ​
Derivative instruments, assets | ​ | ​ | 1 | ​ | ​ | 1 | ​ | ​ | — | ​ | ​ | — | ​
Derivative instruments, liabilities | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6 | ​ | ​ | 6 | ​

​

We estimated the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the following methods and assumptions:

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

Restricted cash and cash equivalents—The carrying amount of our restricted cash and cash equivalents, which are subject to restrictions due to collateral requirements, legislation, regulation or court order approximates fair value due to the near-term maturities of the instruments in which the restricted balances are held. At December 31, 2019, the aggregate carrying amount of such restricted cash and cash equivalents was $558 million, recorded in current assets. At December 31, 2018, the aggregate carrying amount of such restricted cash and cash equivalents was $429 million, including $428 million and $1 million, recorded in current assets and other assets, respectively.

Restricted investments—The carrying amount of our restricted investments, which are subject to restrictions due to court order or pledged for security of certain credit arrangements, approximates fair value because of the near-term maturities of the instruments. At December 31, 2018, the aggregate carrying amount of the restricted investments was $123 million, recorded in current assets.

Debt—The carrying amount of our debt represents the principal amount, net of unamortized discounts, premiums, debt issue costs and fair value adjustments. We measured the estimated fair value of our debt using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.

Derivative instruments—The carrying amount of our derivative instruments represents the estimated fair value of such instruments. We measured the estimated fair value of our derivative instruments using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Note 21—Risk Concentration

Interest rate risk—Financial instruments that potentially subject us to concentrations of interest rate risk include our cash equivalents, short-term investments, restricted cash investments and debt. We are exposed to interest rate risk related to our cash equivalents and short-term investments, as the interest income earned on these investments is based on variable or short-term interest rates, which change with market interest rates. We are also exposed to the interest rate risk related to our fixed-rate debt when we refinance maturing debt with new debt or when we repurchase debt in open market repurchases.

Currency exchange rate risk—Our international operations expose us to currency exchange rate risk. This risk is primarily associated with compensation costs of our employees and purchasing costs from non-U.S. suppliers, which are denominated in currencies other than 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 currency exchange rate risk management strategy 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 and the impact of inflation on local costs, actual local currency needs may vary from those anticipated 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—Financial instruments that potentially subject us to concentrations of credit risk are primarily cash and cash equivalents, short-term investments and trade receivables, both current and long-term. We generally maintain our cash, cash equivalents and short-term investments in time deposits at commercial banks with high credit ratings or mutual funds, which invest exclusively in high-quality money market instruments. We limit the amount of exposure to any one institution and do not believe we are exposed to any significant credit risk.

We earn our revenues by providing our drilling services to integrated oil companies, government-owned or government-controlled oil companies and other independent oil companies. Our receivables are dispersed in various countries. We establish an allowance for doubtful accounts on a case-by-case basis, considering changes in the financial position of a customer, when we believe the required payment of specific amounts owed to us is unlikely to occur. Although we have encountered only isolated credit concerns related to independent oil 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—We require highly skilled personnel to operate our drilling units. We conduct extensive personnel recruiting, training and safety programs. At December 31, 2019, we had approximately 6,600 employees, including approximately 700 persons engaged through contract labor providers. Approximately 47 percent of our total workforce, working primarily in Norway, Brazil, the U.K., Angola and Australia 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. These negotiations sometimes result in strikes and could result in higher personnel expenses, other increased costs or increased operational restrictions, as the outcome of such negotiations affect the market for all offshore employees, not just the union members.

Note 22—Operating Segments, Geographic Analysis and Major Customers

Operating segments—We operate in a single, global market for the provision of contract drilling services to our customers. 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.

Geographic analysis—Operating revenues, presented by country in which they were earned, were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Years ended December 31, |
​ |  | 2019 |  | 2018 |  | 2017 |
Operating revenues | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
U.S. |  | $ | 1,264 | ​ | $ | 1,496 | ​ | $ | 1,527 | ​
Norway | ​ | ​ | 775 | ​ | ​ | 651 | ​ | ​ | 83 | ​
Brazil | ​ | ​ | 125 | ​ | ​ | 110 | ​ | ​ | 335 | ​
Other countries (a) | ​ | ​ | 924 | ​ | ​ | 761 | ​ | ​ | 1,028 | ​
Total operating revenues |  | $ | 3,088 | ​ | $ | 3,018 | ​ | $ | 2,973 | ​

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

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Long-lived assets, presented by country in which they were located, were as follows (in millions):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, |
​ |  | 2019 (a) |  | 2018 |
Long-lived assets | ​ | ​ | ​ | ​ | ​ | ​ | ​
U.S. |  | $ | 6,259 | ​ | $ | 6,257 | ​
Norway | ​ | ​ | 3,203 | ​ | ​ | 3,260 | ​
Greece | ​ | ​ | 2,760 | ​ | ​ | 1,103 | ​
Other countries (b) | ​ | ​ | 7,194 | ​ | ​ | 9,788 | ​
Total long-lived assets |  | $ | 19,416 | ​ | $ | 20,408 | ​

| (a) | The aggregate carrying amount includes the combined total of our property and equipment and our right-of-use assets. |

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

Since 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 in Switzerland, and we do not conduct any operations or have operating revenues in Switzerland.

Major customers—For the year ended December 31, 2019, Royal Dutch Shell plc (together with its affiliates, “Shell”), Equinor ASA (together with its affiliates, “Equinor”) and Chevron Corporation (together with its affiliates, “Chevron”) accounted for approximately 26 percent, 21 percent and 17 percent, respectively, of our consolidated operating revenues. For the year ended December 31, 2018, Shell, Chevron and Equinor accounted for approximately 26 percent, 21 percent, and 18 percent, respectively, of our consolidated operating revenues. For the year ended December 31, 2017, Chevron, Shell and Petróleo Brasileiro S.A. accounted for approximately 29 percent, 17 percent and 14 percent, respectively, of our consolidated operating revenues.

​

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—continued

Note 23—Subsequent Events

Priority guaranteed senior unsecured notes—On January 17, 2020, we issued $750 million aggregate principal amount of 8.00% senior unsecured notes due February 2027 (the “8.00% Senior Notes”), and we received aggregate cash proceeds of $743 million, net of issue costs. The 8.00% Senior Notes are fully and unconditionally guaranteed by Transocean Ltd. and certain wholly owned subsidiaries of Transocean Inc. Such notes rank equal in right of payment to all of our existing and future unsecured unsubordinated obligations and rank structurally senior to the extent of the value of the assets of the subsidiaries guaranteeing the notes. 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 provision, and subsequently, at specified redemption prices. The indenture that governs the 8.00% Senior 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, and consolidate, merge or enter into a scheme of arrangement qualifying as an amalgamation.

Debt redemption—On January 17, 2020, we provided a notice to redeem in full our outstanding 9.00% Senior Notes. On February 18, 2020, we made a payment of $767 million, including the make-whole provision, to redeem the 9.00% Senior Notes, and in the three months ending March 31, 2020, we expect to recognize a loss of approximately $66 million associated with the retirement of debt.

Note 24—Quarterly Results (Unaudited)

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three months ended |
​ |  | March 31, |  | June 30, |  | September 30, |  | December 31, |
​ | ​ | (In millions, except per share data) |
2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating revenues |  | $ | 754 | ​ | $ | 758 | ​ | $ | 784 | ​ | $ | 792 | ​
Operating loss (a) | ​ | ​ | (13) | ​ | ​ | (27) | ​ | ​ | (607) | ​ | ​ | (74) | ​
Net loss (a) | ​ | ​ | (171) | ​ | ​ | (206) | ​ | ​ | (825) | ​ | ​ | (55) | ​
Net loss attributable to controlling interest (a) | ​ | ​ | (171) | ​ | ​ | (208) | ​ | ​ | (825) | ​ | ​ | (51) | ​
Per share loss | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic |  | $ | (0.28) | ​ | $ | (0.34) | ​ | $ | (1.35) | ​ | $ | (0.08) | ​
Diluted |  | $ | (0.28) | ​ | $ | (0.34) | ​ | $ | (1.35) | ​ | $ | (0.08) | ​
Weighted-average shares outstanding | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 611 | ​ | ​ | 612 | ​ | ​ | 613 | ​ | ​ | 613 | ​
Diluted | ​ | ​ | 611 | ​ | ​ | 612 | ​ | ​ | 613 | ​ | ​ | 613 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating revenues |  | $ | 664 | ​ | $ | 790 | ​ | $ | 816 | ​ | $ | 748 | ​
Operating loss (b) | ​ | ​ | (4) | ​ | ​ | (917) | ​ | ​ | (305) | ​ | ​ | (25) | ​
Net loss (b) | ​ | ​ | (212) | ​ | ​ | (1,139) | ​ | ​ | (409) | ​ | ​ | (243) | ​
Net loss attributable to controlling interest (b) | ​ | ​ | (210) | ​ | ​ | (1,135) | ​ | ​ | (409) | ​ | ​ | (242) | ​
Per share loss | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic |  | $ | (0.48) | ​ | $ | (2.46) | ​ | $ | (0.88) | ​ | $ | (0.48) | ​
Diluted |  | $ | (0.48) | ​ | $ | (2.46) | ​ | $ | (0.88) | ​ | $ | (0.48) | ​
Weighted-average shares outstanding | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 438 | ​ | ​ | 462 | ​ | ​ | 463 | ​ | ​ | 506 | ​
Diluted | ​ | ​ | 438 | ​ | ​ | 462 | ​ | ​ | 463 | ​ | ​ | 506 | ​

(a) | Third quarter included an aggregate loss of $583 million, primarily associated with the impairment of certain drilling units and other equipment classified as assets held for sale and $26 million associated with the impairment of certain right-of-use assets and leasehold improvements related to our leases. First quarter, second quarter, third quarter and fourth quarter included an aggregate loss of $41 million associated with the retirement of debt. First quarter and second quarter included a bargain purchase gain of $11 million associated with the Ocean Rig acquisition. Fourth quarter included a gain of $132 million associated with the termination of construction contracts for two ultra-deepwater drillships.

(b) | First quarter, third quarter and fourth quarter included an aggregate loss of $24 million associated with Songa and Ocean Rig acquisition costs. Fourth quarter included a bargain purchase gain of $10 million associated with the Ocean Rig acquisition. Second quarter included a loss of $462 million associated with the impairment of our goodwill. Second quarter, third quarter and fourth quarter included an aggregate loss of $999 million associated with the impairment of certain drilling units classified as assets held for sale.

​

​

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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 and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the United States (“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, 2019.

Internal control over financial reporting—There has been no change to our internal control over financial reporting during the quarter ended December 31, 2019 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.

​

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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 Accounting 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 2020 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, 2019. Certain information with respect to our executive officers is set forth in Item 4 of this annual report under the caption “Executive Officers of the Registrant.”

​

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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 | ​ | 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, 2017 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves and allowances deducted from asset accounts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Allowance for excess and obsolete materials and supplies | ​ | ​ | 153 | ​ | ​ | 24 | ​ | ​ | — | ​ | ​ | 36 | (a) | ​ | 141 | ​
Valuation allowance on deferred tax assets | ​ | ​ | 412 | ​ | ​ | 162 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 574 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31, 2018 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves and allowances deducted from asset accounts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Allowance for excess and obsolete materials and supplies | ​ | ​ | 141 | ​ | ​ | 12 | ​ | ​ | — | ​ | ​ | 19 | (a) | ​ | 134 | ​
Valuation allowance on deferred tax assets | ​ | ​ | 574 | ​ | ​ | 67 | ​ | ​ | 40 | (b) | ​ | — | ​ | ​ | 681 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31, 2019 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Reserves and allowances deducted from asset accounts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Allowance for excess and obsolete materials and supplies | ​ | ​ | 134 | ​ | ​ | 3 | ​ | ​ | — | ​ | ​ | 10 | (a) | ​ | 127 | ​
Valuation allowance on deferred tax assets | ​ | ​ | 681 | ​ | ​ | 37 | ​ | ​ | — | ​ | ​ | 2 | (c) | ​ | 716 | ​

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

(b) | Amount primarily related to the following: (i) adjustments of $26 million to the valuation allowance and related deferred tax assets with corresponding adjustments to retained earnings associated with our adoption of the accounting standards update that requires an entity to recognize in the period in which it occurs the income tax consequences of an intra entity transfer of an asset other than inventory and (ii) an adjustment of $14 million to the valuation allowance related to deferred tax assets acquired in business combinations.

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

​

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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
​ | 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 Current Report on Form 8-K (Commission File No. 001-38373) filed on May 13, 2019
​ | 3.2 | ​ | Organizational Regulations of Transocean Ltd., adopted November 18, 2016 | ​ | Exhibit 3.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on November 23, 2016
​ | 4.1 | ​ | Description of Shares of Transocean Ltd. | ​ | Filed herewith
​ | 4.2 | ​ | 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
​ | 4.3 | ​ | 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
​ | 4.4 | ​ | 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
​ | 4.5 | ​ | 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
​ | 4.6 | ​ | 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 | ​ | Filed herewith
​ | 4.7 | ​ | 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
​ | 4.8 | ​ | 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
​ | 4.9 | ​ | 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
​ | 4.10 | ​ | 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
​ | 4.11 | ​ | 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
​ | 4.12 | ​ | 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
​ | 4.13 | ​ | 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
​ | 4.14 | ​ | 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
​ | 4.15 | ​ | 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

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​ | ​ | ​ | ​ | ​ | ​
--- | --- | --- | --- | --- | ---
Number | ​ | Description |  | Location
​ | 4.16 | ​ | Officers’ Certificate establishing the terms of the 7.50% Note 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
​ | 4.17 | ​ | 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
​ | 4.18 | ​ | 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
​ | 4.19 | ​ | 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
​ | 4.20 | ​ | 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
​ | 4.21 | ​ | 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
​ | 4.22 | ​ | 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
​ | 4.23 | ​ | Terms of 7% Note 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
​ | 4.24 | ​ | Senior 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
​ | 4.25 | ​ | 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
​ | 4.26 | ​ | 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
​ | 4.27 | ​ | 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
​ | 4.28 | ​ | 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
​ | 4.29 | ​ | 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
​ | 4.30 | ​ | 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
​ | 4.31 | ​ | 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
​ | 4.32 | ​ | 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
​ | 4.33 | ​ | 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
​ | 4.34 | ​ | 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 October 19, 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
​ | 4.35 | ​ | 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

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​ | ​ | ​ | ​ | ​ | ​
--- | --- | --- | --- | --- | ---
Number | ​ | Description |  | Location
​ | 4.36 | ​ | 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
​ | 4.37 | ​ | 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
​ | 4.38 | ​ | 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
​ | 4.39 | ​ | 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
​ | 4.40 | ​ | 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
​ | 4.41 | ​ | 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
​ | 4.42 | ​ | 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
* | 10.1 | ​ | First Amendment to Transocean Ltd. 2015 Long-Term Incentive Plan | ​ | Annex B to Transocean Ltd.’s definitive proxy statement (Commission File No. 001-38373) filed on March 20, 2018
​ | 10.2 | ​ | 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
​ | 10.3 | ​ | 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.
* | 10.4 | ​ | 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
* | 10.5 | ​ | 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
* | 10.6 | ​ | 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
* | 10.7 | ​ | 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
* | 10.8 | ​ | 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
* | 10.9 | ​ | 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
* | 10.10 | ​ | 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
* | 10.11 | ​ | 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
* | 10.12 | ​ | 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
* | 10.13 | ​ | 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
* | 10.14 | ​ | 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
* | 10.15 | ​ | 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

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​ | ​ | ​ | ​ | ​ | ​
--- | --- | --- | --- | --- | ---
Number | ​ | Description |  | Location
* | 10.16 | ​ | 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
* | 10.17 | ​ | 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
​ | 10.18 | ​ | Terms and Conditions of the July 2008 Nonqualified Share Option Award | ​ | Exhibit 10.2 to Transocean I nc.’s Annual Report on Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2008
* | 10.19 | ​ | 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
* | 10.20 | ​ | 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
* | 10.21 | ​ | 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
​ | 10.22 | ​ | 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
* | 10.23 | ​ | 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
* | 10.24 | ​ | 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
* | 10.25 | ​ | 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
* | 10.26 | ​ | 1997 Long-Term Incentive Plan | ​ | GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997
* | 10.27 | ​ | Amendment to 1997 Long Term Incentive 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
* | 10.28 | ​ | 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
* | 10.29 | ​ | 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
* | 10.30 | ​ | 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
* | 10.31 | ​ | 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
* | 10.32 | ​ | GlobalSantaFe Corporation 2001 Long-Term Incentive Plan | ​ | Exhibit A to GlobalSantaFe Corporation’s definitive proxy statement (Commission File No. 001-1 4634) filed on March 21, 2001
* | 10.33 | ​ | 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
* | 10.34 | ​ | 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
* | 10.35 | ​ | 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

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​ | ​ | ​ | ​ | ​ | ​
--- | --- | --- | --- | --- | ---
Number | ​ | Description |  | Location
* | 10.36 | ​ | 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
* | 10.37 | ​ | Transocean U.S. Supplemental Savings Plan | ​ | 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
​ | 10.38 | ​ | 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
* | 10.39 | ​ | 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
​ | 10.40 | ​ | 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
* | 10.41 | ​ | 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
* | 10.42 | ​ | Transocean Ltd. 2015 Long-Term Incentive Plan | ​ | Annex B to Transocean Ltd.’s definitive proxy statement (Commission File No. 000-53533) filed on March 23, 2015
​ | 10.43 | ​ | 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
​ | 10.44 | ​ | 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
​ | 10.45 | ​ | 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
* | 10.46 | ​ | Employment Agreement among Transocean Ltd., Transocean Offshore Deepwater Drilling Inc. and John Stobart dated December 1, 2015 | ​ | Exhibit 10.60 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2015
* | 10.47 | ​ | Employment Agreement with Keelan Adamson dated August 10, 2018 | ​ | Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 001-38373) filed on August 14, 2018.
* | 10.48 | ​ | 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
* | 10.49 | ​ | 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
* | 10.50 | ​ | Amended and Restated Performance Award and Cash Bonus Plan of Transocean Ltd. | ​ | Filed herewith
​ | 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

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​ | ​ | ​ | ​ | ​ | ​
--- | --- | --- | --- | --- | ---
Number | ​ | Description |  | Location
​ | 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, 2019 and December 31, 2018; (ii) our consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017; (iii) our consolidated statements of comprehensive loss for the years ended December 31, 2019, 2018 and 2017; (iv) our consolidated statements of equity for the years ended December 31, 2019, 2018 and 2017; (v) our consolidated statements of cash flows for the years ended December 31, 2019, 2018 and 2017; 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, 2019, 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.

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.

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​

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 18, 2020.

​ | ​ | ​
​ | 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 18, 2020.

​ | ​ | ​ | ​
Signature | ​ | Title | ​
​ | ​ | ​ | ​
* | ​ | Chairman of the Board of Directors | ​
Chadwick C. Deaton | ​ | ​ | ​
​ | ​ | ​ | ​
/s/ Jeremy D. Thigpen | ​ | President and 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 | ​
Tan Ek Kia | ​ | ​ | ​
​ | ​ | ​ | ​
* | ​ | Director | ​
Vincent J. Intrieri | ​ | ​ | ​
​ | ​ | ​ | ​
* | ​ | Director | ​
Samuel Merksamer | ​ | ​ | ​
​ | ​ | ​ | ​
* | ​ | Director | ​
Frederick W. Mohn | ​ | ​ | ​
​ | ​ | ​ | ​
* | ​ | Director | ​
Edward R. Muller | ​ | ​ | ​
​ | ​ | ​ | ​
By: /s/ David Tonnel | ​ | ​ | ​
(Attorney-in-Fact) | ​ | ​ | ​

​

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