20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

(Mark One)

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

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

For the fiscal year ended December 31, 2020

OR

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

For the transition period from                      to                     

OR

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

Date of event requiring this shell company report                     

Commission file number 001-35704

SEADRILL PARTNERS LLC

(Exact Name of Registrant as Specified in Its Charter)

Republic of The Marshall Islands

(Jurisdiction of Incorporation or Organization)

2nd floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London,

W4 5YS, United Kingdom

Telephone: +44 20 8811 4700

(Address of Principal Executive Offices)

John Roche

2nd floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London,

W4 5YS, United Kingdom

Telephone: +44 20 8811 4700

E-mail: post@seadrill.com

(Name, Telephone, E-mail and/or Facsimile Number and Address of Company Contact Person)

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

Title of Each Class	Trading symbol	Name of Each Exchange on which Registered
None	None	None

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

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Common units representing limited liability company interests

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

7,527,830 Common Units representing limited liability company interests

1,654,335 Subordinated Units representing limited liability company interests

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

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ☐	Accelerated filer   ☐
Non-accelerated filer ☒	Emerging growth company ☐

                   

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

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

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP  ☒ International Financial Reporting Standards as Issued
by the International Accounting Standards Board  ☐ Other  ☐

If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.    Item 17  ☐    Item 18  ☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

SEADRILL PARTNERS LLC

INDEX TO REPORT ON FORM 20-F

PART I
Item 1.	Identity of Directors, Senior Management and Advisers	1
Item 2.	Offer Statistics and Expected Timetable	1
Item 3.	Key Information	1
A.	Selected Financial Data	1
B.	Capitalization and Indebtedness	2
C.	Reasons for the Offer and Use of Proceeds	2
D.	Risk Factors	2
Item 4.	Information on the Company	31
A.	History and Development of the Company	31
B.	Business Overview	33
C.	Organizational Structure	38
D.	Property, Plant and Equipment	39
Item 4A.	Unresolved Staff Comments	39
Item 5.	Operating and Financial Review and Prospects	40
A.	Operating Results	46
B.	Liquidity and Capital Resources	50
C.	Research and Development, Patents and Licenses	54
D.	Trend Information	55
E.	Safe Harbor	55
Item 6.	Directors, Senior Management and Employees	55
A.	Directors and Senior Management	56
B.	Compensation	57
C.	Board Practices	58
D.	Employees	58
E.	Unit Ownership	59
Item 7.	Major Unitholders and Related Party Transactions	59
A.	Major Unitholders	59
B.	Related Party Transactions	60
C.	Interests of Experts and Counsel	60
Item 8.	Financial Information	61
A.	Consolidated Statements and Other Financial Information	61
B.	Significant Changes	61
Item 9.	The Offer and Listing	61
A.	Offer and Listing Details	61
B.	Plan of distribution	61
C.	Markets	61
D.	Selling Shareholders	61
E.	Dilution	61
F.	Expenses of the issue	61
Item 10.	Additional Information	62
A.	Share Capital	62
B.	Memorandum and Articles of Association	62
C.	Material Contracts	62
D.	Exchange Controls	62
E.	Taxation	62
F.	Dividends and Paying Agents	68

G.	Statements by Experts	68
H.	Documents on Display	68
I.	Subsidiary Information	68
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	68
Item 12.	Description of Securities Other than Equity Securities	70
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	70
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	70
Item 15.	Controls and Procedures	71
Item 16A.	Audit Committee Financial Expert	71
Item 16B.	Code of Ethics	71
Item 16C.	Principal Accountant Fees and Services	71
Item 16D.	Exemptions from the Listing Standards for Audit Committees	72
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	72
Item 16F.	Change in Registrants' Certifying Accountant	72
Item 16G.	Corporate Governance	73
Item 16H.	Mine Safety Disclosure	73
PART III
Item 17.	Financial Statements	73
Item 18.	Financial Statements	73
Item 19.	Exhibits	74

Presentation of Information in this Annual Report

This annual report on Form 20-F for the year ended December 31, 2020 ("the annual report"), should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in this report. Unless the context otherwise requires, references in this annual report to "Seadrill Partners LLC," "Seadrill Partners," the "Company," "we," "our," "us" or similar terms refer to Seadrill Partners LLC, a Marshall Islands limited liability company, or any one or more of its subsidiaries (including OPCO, as defined below), or to all of such entities, and, for periods prior to the Company's initial public offering ("IPO") on October 24, 2012, the Company's combined entity. References to the Company's "combined entity" refer to the subsidiaries of Seadrill Limited that had interests in the drilling units in the Company's initial fleet prior to the Company's initial public offering, or in the case of drilling units subsequently acquired from Seadrill Limited in transactions between parties under common control, the subsidiaries of Seadrill Limited that had interests in the drilling units prior to the date of acquisition. References in this annual report to "Seadrill" or "Seadrill Limited" refer, depending on the context, to Seadrill Limited (OTCQX: SDRLF) and to any one or more of its direct and indirect subsidiaries. References to "Seadrill Management" refer to Seadrill Management Ltd, the entity that provides the Company with personnel and management, administrative, financial and other support services.

The Company owns (i) a 58% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through the Company's 100% ownership of its general partner, Seadrill Operating GP LLC, (ii) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC and (iii) a 100% interest in Seadrill Partners Operating LLC. Seadrill Operating LP owns: (i) a 100% interest in the entities that own and operate the West Aquarius, West Vencedor, West Leo and West Polaris (ii) an approximate 56% interest in the entity that owns and operates the West Capella and (iii) a 100% limited liability company interest in Seadrill Partners Finco LLC. Seadrill Capricorn Holdings LLC owns 100% of the entities that own and operate the West Capricorn, West Sirius, West Auriga and West Vela. Seadrill Partners Operating LLC owns 100% of the entities that own and operate the T-15 and T-16. Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC are collectively referred to as "OPCO."

All references in this annual report to "OPCO" when used in a historical context refer to OPCO's predecessor companies and their subsidiaries, and when used in the present tense or prospectively refer to OPCO and its subsidiaries, collectively, or to OPCO individually, as the context may require.

References in this annual report to "Seadrill Member" refer to the owner of the Seadrill Member interest, which is a non-economic limited liability company interest in Seadrill Partners and is currently held by Seadrill Member LLC, a wholly owned subsidiary of Seadrill. Certain references to the "Seadrill Member" refer to Seadrill Member LLC, as the context requires.

References in this annual report to "BP", "Reliance", "ExxonMobil", "Petronas", "Chevron" and "Tullow" refer to subsidiaries of BP Plc, Reliance Petroleum Ltd., ExxonMobil Corporation, Petroliam Nasional Berhad (PETRONAS), Chevron Corporation and Tullow Plc respectively, that are or were the Company's customers.

Important Information Regarding Forward Looking Statements

Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements, which are other than statements of historical or present facts or conditions.

This annual report and any other written or oral statements made by us or on our behalf may include forward-looking statements which reflect our current views with respect to future events and financial performance. The words "believe," "anticipate," "intend," "estimate," "forecast," "project," "plan," "potential," "may," "should," "expect" and similar expressions identify forward-looking statements.

The forward-looking statements in this annual report are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.

In addition to these important factors and matters discussed elsewhere in this annual report, and in the documents incorporated by reference in this annual report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:

•the impact of active negotiations, contingency planning efforts, rulings and outcomes with respect to a comprehensive restructuring of our debt under Chapter 11 proceedings with the U.S. Bankruptcy Court, or the "Bankruptcy Court", the outcome of which is uncertain;

•our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing and the related increased performance and credit risks associated with our constrained liquidity position and capital structure;

•our ability to maintain and obtain adequate financing to support our business plans post-emergence from Chapter 11;

•the length of time that we will operate under Chapter 11 protection;

•risks associated with third-party motions in the Chapter 11 proceedings that may interfere with the solicitation and ability to confirm and consummate a plan of reorganization;

•our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, unionization, or otherwise, or to retain employees, customers or suppliers as a result of our financial condition generally or as a result of the Chapter 11 proceedings;

•general economic, political and business conditions globally, including global health threats, such as the Coronavirus, or COVID-19, outbreak on us, our customers and suppliers;

i

•the COVID-19 global pandemic, the related public health measures implemented by governments worldwide and the decline in oil prices during 2020, including the duration and severity of the outbreak, the duration of the price and demand decline and the extent of disruptions to our operations;

•the Company's distribution policy and the Company's ability to make cash distributions on the Company's units or any resumption in such distributions and the amount of such distributions;

•the future financial condition, liquidity or results of operations of the Company or Seadrill;

•offshore drilling market conditions, including supply and demand;

•the ability of the Company and OPCO to comply with financing agreements and the effect of restrictive covenants in such agreements;

•the ability of the Company's drilling units to perform satisfactorily or to the Company's expectations;

•fluctuations in the price of oil;

• discoveries of new sources of oil that do not require deepwater drilling units;

•the development of alternative sources of fuel and energy;

•technological advances, including in production, refining and energy efficiency;

•weather events and natural disasters;

•the Company's ability to meet any future capital expenditure requirements;

•the Company's ability to maintain operating expenses at adequate and profitable levels;

•expected costs of maintenance or other work performed on the Company's drilling units and any estimates of downtime;

•the Company's ability to leverage Seadrill's relationship and reputation in the offshore drilling industry;

•the Company's ability to purchase drilling units in the future, including from Seadrill;

•increasing the Company's ownership interest in OPCO;

•customer contracts, including contract backlog, contract terminations and contract revenues;

•delay in payments by, or disputes with the Company's customers under its drilling contracts;

•termination of the Company's drilling contracts due to force majeure or other events;

•the financial condition of the Company's customers and their ability and willingness to fund oil exploration, development and production activity;

•the Company's ability to comply with, maintain, renew or extend its existing drilling contracts;

•the Company's ability to re-contract its drilling units upon conclusion of its existing drilling contracts at profitable dayrates;

•the Company's ability to respond to new technological requirements in the areas in which the Company operates;

•the occurrence of any accident involving the Company's drilling units or other drilling units in the industry;

•changes in governmental regulations that affect the Company and the interpretations of those regulations, particularly those that relate to environmental matters, export or import and economic sanctions or trade embargo matters, regulations applicable to the oil industry and tax and royalty legislation;

•competition in the offshore drilling industry and other actions of competitors, including decisions to deploy or scrap drilling units in the areas in which the Company currently operates;

•the availability on a timely basis of drilling units, supplies, personnel and oil field services in the areas in which the Company operates;

•military operations, terrorist acts, wars or embargoes;

•potential disruption of operations due to accidents, political events, piracy or acts by terrorists;

•the Company's ability to obtain financing in sufficient amounts and on adequate terms;

•workplace safety regulation and employee claims;

•the cost and availability of adequate insurance coverage;

•the Company's fees and expenses payable under the advisory, technical and administrative services agreements and the management and administrative services agreements;

•the taxation of the Company and distributions to the Company's unitholders;

•future sales of the Company's common units in the public market;

•acquisitions and divestitures of assets and businesses by Seadrill; and

•the Company's business strategy and other plans and objectives for future operations.

We caution readers of this annual report not to place undue reliance on these forward-looking statements, which speak only as of their dates. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward looking statement.

ii

PART I

Item 1.         Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.         Offer Statistics and Expected Timetable

Not applicable.

Item 3.        Key Information

    A.     Selected Financial Data

The following table presents, in each case for the periods and as of the dates indicated, the Company's selected Consolidated and Combined Carve-Out financial and operating data. The following financial data should be read in conjunction with Item 5 - "Operating and Financial Review and Prospects" and the Company's historical Consolidated Financial Statements and the notes thereto included elsewhere in this annual report. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding going concern as described in Note 1 - "General information" to the Consolidated Financial Statements included herein.

	Year Ended December 31,
	2020		2019		2018		2017		2016
	(In $ millions, except per unit data)
Statement of Operations Data:
Total operating revenues (1)	538.1		750.0		1,038.2		1,128.4		1,600.3
Total operating expenses	(571.7)		(700.1)		(678.0)		(755.6)		(782.2)
Total other operating items (2)	(4,210.4)		0.7		(3.2)		90.7		—
Net operating (loss)/income	(4,244.0)		50.6		357.0		463.5		818.1
Total financial items	(314.9)		(273.9)		(196.3)		(187.9)		(185.9)
(Loss)/Income before income taxes	(4,558.9)		(223.3)		160.7		275.6		632.2
Income tax (expense)/benefit	(30.0)		36.1		(86.7)		(40.3)		(86.5)
Net (loss)/income	(4,588.9)		(187.2)		74.0		235.3		545.7
(Loss)/ Earnings per unit (common and subordinated)
Common unitholders (U.S. Dollars) (3)	$	(277.80)	$	(10.12)	$	7.45	$	18.76	$	31.97
Subordinated unitholders (U.S. Dollars) (3)	$	(277.80)	$	(10.12)	$	—	$	—	$	22.85

(1)Total operating revenues include amounts recognized as early termination fees under the offshore drilling contracts which have been terminated prior to the contract end date.

(2)Total other operating items in 2020 are a result of an impairment against all of our drilling units, the gain in 2019 and 2017 primarily related to a decrease in the fair value of contingent liabilities to Seadrill for the purchase of the West Polaris in 2015 and the loss in 2018 was a result of impairment of goodwill. Refer to Note 9 - "Other operating items" to the Consolidated Financial Statements included herein for further information.

(3)These amounts have been updated to reflect the 1 for 10 reverse stock split on July 2, 2019.

	As of December 31,
	2020	2019	2018	2017	2016
	(In $ millions)
Balance Sheet Data:
Cash and cash equivalents	378.4	560.0	841.6	848.6	767.6
Drilling units	428.3	4,840.8	5,005.6	5,170.9	5,340.9
Total assets	927.2	5,680.0	6,185.4	6,530.8	6,780.7
Total interest bearing debt (1)	2,727.1	2,878.2	3,059.1	3,367.8	3,600.6
Total (deficit)/equity	(2,065.2)	2,523.7	2,714.2	2,701.8	2,535.8

(1)On filing for Chapter 11 on December 1, 2020, the interest bearing debt balance has been reclassified to liabilities subject to compromise. Refer to Note 16 - "Debt" to the Consolidated Financial Statements included herein for further information.

1

	Year Ended December 31,
	2020	2019	2018	2017	2016
	(In $ millions, except fleet and unit data)
Cash Flow Data:
Net cash provided by/(used in) operating activities	165.0	(26.0)	434.1	476.2	873.8
Net cash (used in)/provided by investing activities	(9.4)	(29.7)	(23.4)	(11.1)	97.6
Net cash used in financing activities	(337.2)	(225.9)	(416.7)	(384.9)	(522.1)
Net (decrease)/increase in cash and cash equivalents	(181.6)	(281.6)	(7.0)	81.0	448.6
Fleet Data (at end of period):
Number of drilling units	11	11	11	11	11
Average age of drilling units (years)	9.7	8.7	7.7	6.7	5.7
Other Financial Data:
Capital expenditures (1)	28.7	111.1	115.0	121.6	61.1
Distributions declared per unit (2) (3)	—	0.1200	3.1000	4.0000	5.5000
Members' Capital (at end of period):
Total members' capital (excluding non-controlling interest)	(1,315.9)	1,235.0	1,329.7	1,303.7	1,192.6
Common Unitholders—units (3)	7,527,830	7,527,830	7,527,830	7,527,830	7,527,830
Subordinated Unitholders—units (3)	1,654,335	1,654,335	1,654,335	1,654,335	1,654,335

(1)Capital expenditures include long-term maintenance.

(2)Distributions attributable to the year. Distributions were declared only with respect to the common units in 2019, 2018 and 2017.

(3)These amounts have been updated to reflect the 1 for 10 reverse stock split on July 2, 2019.

    B.     Capitalization and Indebtedness

Not applicable.

    C.     Reasons for the Offer and Use of Proceeds

Not applicable.

D.     Risk Factors

Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following summarizes risks that may materially affect our business, financial condition, results of operations, cash available for distributions or the trading price of our common units. The occurrence of any of the events described in this section could materially and negatively affect our business, financial condition, results of operations, cash available for the payment of distributions or the trading price of our common units. Unless otherwise indicated, all information concerning our business and our assets is as of December 31, 2020. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.

Summary of Risk Factors

Risks Relating to Our Chapter 11 Proceedings

•We and a substantial number of our consolidated subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and we are subject to the risks and uncertainties associated with such bankruptcy proceedings.

•We may not be able to obtain Bankruptcy Court confirmation of the plan of reorganization or may have to modify the terms of the plan of reorganization.

•We may have insufficient liquidity for our business operations during the Chapter 11 proceedings.

•Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may not be successful in its execution.

•In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

•Trading in our securities during the term of the Chapter 11 proceedings is highly speculative and poses substantial risks.

2

Risks Relating to Our Company and Our Business

•The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition.

•The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.

•Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted.

•Our contract backlog for our fleet of drilling units may not be realized.

•We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts have expired or been terminated.

•The market value of our drilling units may further decrease.

•Our business and operations involve numerous operating hazards, and in the current market we are increasingly required to take additional contractual risk in our customer contracts and we may not be able to procure insurance to adequately cover potential losses.

•We derive the majority of our revenue from a small number of customers, and the loss of any of these customers could result in a material loss of revenues and cash flow.

•Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including reactivation, operating and maintenance costs.

•Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies.

•We may be unable to obtain, maintain and/or renew permits necessary for our operations or experience delays in obtaining such permits including the class certifications of rigs.

•The international nature of our operations involves additional risks including foreign government intervention in relevant markets.

•Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations.

•We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

•Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act 1977, or the "FCPA," or the UK Bribery Act 2010, or the "UK Bribery Act," could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.

•If our drilling units are located in countries that are subject to or targeted by economic sanctions, export restrictions or other operating restrictions imposed by the United States or other governments, our reputation and the market for our debt and common units could be adversely affected.

•A continuing economic downturn could have a material adverse effect on our revenue, profitability and financial position.

•Our ability to operate our drilling units in the U.S. Gulf of Mexico could be impaired by governmental regulation, particularly in the aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout.

•Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.

•Climate change and the regulation of greenhouse gases could have a negative impact on our business.

•We face various risks associated with increased activism against oil and natural gas exploration and development activities.

•Acts of terrorism, piracy, cyber-attacks, political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.

•We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.

•The failure to consummate or integrate acquisitions in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.

•Public health threats, such as the coronavirus, or COVID-19, outbreak could have an adverse effect on our operations and financial results.

Risks Relating to an Investment in our Units

•Our filing for Chapter 11 protection under the Bankruptcy Code could result in a significant reduction or elimination of current shareholder positions.

•Our common units are currently traded on the OTC Pink Open Market, which could adversely affect the market liquidity of our common units and harm our business.

•The market price of our common units has fluctuated widely and may fluctuate widely in the future.

•Increases in interest rates may cause the market price of our common units to decline.

•Because our ownership interest in OPCO currently represents our only cash-generating asset, our cash flow depends completely on OPCO's ability to make distributions to its owners, including us.

•We may not pay distributions in the future including the minimum quarterly distribution on common units and subordinated units.

•Our level of debt and restrictions in our debt agreements may prevent us from paying distributions.

•Restrictions under Marshall Islands law may prevent us from paying distributions.

•Our common unitholders have limited voting rights compared to the Seadrill Member, who may favor its own interests to the detriment of the common unitholders.

3

•Although we control OPCO, we owe duties to OPCO and its other owner, Seadrill, which may conflict with our interests and the interests of our unitholders.

•Our operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Seadrill Member, and even if public unitholders are dissatisfied, they will be unable to remove the Seadrill Member without Seadrill's consent, unless Seadrill's ownership interest in us is decreased; all of which could diminish the trading price of our common units.

•In establishing cash reserves, the Board may reduce the amount of cash available for distribution to the unitholders.

•Unitholders have limited voting rights, and our operating agreement restricts the voting rights of the unitholders owning more than 5% of our common units.

•Our operating agreement may limit the duties of the Seadrill Member and our directors and officers to our unitholders and restricts the remedies available to our unitholders for actions taken by the Seadrill Member or our directors and officers.

•Seadrill's ownership interest in us could decrease, and substantial future sales of our common units, could lead to a reduction in the trading price of our common units.

•If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940 which could force us to restructure and restrict our future activities.

•The Seadrill Member, as the initial holder of all of the incentive distribution rights, may elect to cause us to issue additional common units to it in connection with a resetting of the target distribution levels related to the Seadrill Member's incentive distribution rights without the approval of the conflicts committee of the Board or holders of our common units and subordinated units. This may result in lower distributions to holders of the common units in certain situations.

•We may issue additional equity securities, including securities senior to the common units, without the approval of our unitholders, which could dilute the ownership interests of our existing unitholders.

•Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

•The Seadrill Member has a limited call right that may require our common unitholders to sell their common units at an undesirable time or price.

•Unitholders may have liability to repay distributions.

•Because we are a foreign limited liability company, you may not have the same rights that a unitholder in a U.S. limited liability company may have.

•U.S. tax authorities may treat us as a "passive foreign investment company" for U.S. federal income tax purposes, which may have adverse tax consequences for U.S. unitholders.

General Risk Factors

•Interest rate fluctuations could affect our earnings and cash flow.

•Fluctuations in exchange rates and the non-convertibility of currencies could result in losses to us.

•A change in tax laws in any country in which we operate could result in higher tax expense.

•A loss of a major tax dispute or a successful tax challenge to our tax positions, including our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in higher taxes on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

•A change in laws and regulations in any country in which we operate could have a negative impact on our business.

•We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.

•If we fail to comply with requirements relating to internal control over financial reporting our business could be harmed and our common unit price could decline.

•Data protection and regulations related to privacy, data protection and information security could increase our costs, and our failure to comply could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations, as well as have an impact on our reputation.

Risks Relating to Our Chapter 11 Proceedings

We and a substantial number of our consolidated subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and we are subject to the risks and uncertainties associated with such bankruptcy proceedings.

On December 1, 2020 we filed a voluntary petition for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas.

We are subject to a number of risks and uncertainties associated with the Chapter 11 proceedings, which may lead to potential adverse effects on our liquidity, results of operations or business prospects. We cannot assure you of the outcome of the Chapter 11 proceedings. Risks associated with the Chapter 11 proceedings include the following:

•our ability to continue as a going concern;

•our ability to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 proceedings and the outcomes of Bankruptcy Court rulings of the proceedings in general;

•our ability to comply with and to operate under any cash collateral orders and the cash management orders entered by the Bankruptcy Court;

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•the length of time we will operate under the Chapter 11 proceedings and our ability to successfully emerge, including with respect to obtaining any necessary regulatory approvals and to complete certain corporate reorganizations;

•our ability to negotiate, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;

•risks associated with the actions and decisions of our creditors, third party motions, proceedings and litigation in the Chapter 11 proceedings;

•the ability to maintain sufficient liquidity throughout the Chapter 11 proceedings;

•increased costs related to the bankruptcy filing, operating in Chapter 11 and other litigation;

•the ability of third parties to seek and obtain Bankruptcy Court approval to convert the Chapter 11 proceedings to Chapter 7 proceedings;

•our ability to manage contracts that are critical to our operation, and to obtain and maintain appropriate credit and other terms with customers, suppliers and service providers;

•our ability to attract, retain and motivate key employees;

•our ability to satisfy or waive certain conditions precedent to the effectiveness of the plan of reorganization to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•the disposition or resolution of all pre-petition claims against us; and

•our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties.

The Chapter 11 proceedings limit the flexibility of our management team in running the Debtors’ business and has consumed and will continue to consume a substantial portion of the time and attention of our management team.

While we operate our business as debtors-in-possession under supervision by the Bankruptcy Court, we are required to obtain the approval of the Bankruptcy Court with respect to our business, including activities and transactions that are outside the ordinary course of business. Bankruptcy Court approval of non-ordinary course activities entails preparation and filing of appropriate motions with the Bankruptcy Court, negotiation with various parties-in-interest, including any statutory committees appointed in our Chapter 11 proceedings, and one or more hearings. Such committees and parties-in-interest may be heard at any Bankruptcy Court hearing and may raise objections with respect to these motions. This process could delay major transactions and limit our ability to respond quickly to opportunities and events in the marketplace. Furthermore, in the event the Bankruptcy Court does not approve a proposed activity or transaction, we could be prevented from engaging in activities and transactions that we believe are beneficial to us.

Additionally, the terms of any cash collateral orders entered by the Bankruptcy Court will limit our ability to undertake certain business initiatives. These limitations may include, among other things, our ability to:

•sell assets outside the normal course of business;

•consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

•grant liens;

•incur debt for borrowed money outside the ordinary course of business; and

•finance our operations, investments or other capital needs or to engage in other business activities that would be in our interests.

Additionally, while the Chapter 11 proceedings continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 proceedings instead of focusing exclusively on our business operations. This diversion of attention may have a material adverse effect on the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.

The Chapter 11 proceedings and operating under Bankruptcy Court protection for a long period may disrupt our business and may materially and adversely affect our operations.

We have attempted to minimize the adverse effect of the Chapter 11 proceedings on our relationships with our employees, suppliers, customers and other parties. Nonetheless, our relationships with our customers, suppliers and employees may be adversely impacted by negative publicity and our operations could be materially and adversely affected. In addition, the Chapter 11 proceedings could negatively affect our ability to attract new employees and retain existing high performing employees or executives, which could materially and adversely affect our operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings.

The Bankruptcy Code provides that the confirmation of a plan of reorganization may discharge a debtor from debts arising prior to the petition date. All claims that arose before the petition date are subject to compromise and/or treatment under a plan of reorganization. The Bankruptcy Code excludes certain pre-petition claims from discharge for corporate debtors, including certain debts owed to governmental entities obtained by, among other things, false representations or actual fraud. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

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We may not be able to obtain Bankruptcy Court confirmation of the plan of reorganization or may have to modify the terms of the plan of reorganization.

We may not receive the accepting votes necessary to confirm the plan of reorganization. Even if approved by each class of holders of claims and interests entitled to vote (a “Voting Class”), the Bankruptcy Court may, as a court of equity, exercise substantial discretion and could choose not to confirm the plan. Bankruptcy Code Section 1129 requires, among other things, a showing that confirmation of the plan will not be followed by liquidation or the need for further financial reorganization for the Debtors, and that the value of distributions to dissenting holders of claims and interests will not be less than the value such holders would receive if the Debtors liquidated under Chapter 7 of the Bankruptcy Code. Although we believe that the plan will satisfy such tests, there can be no assurance that the Bankruptcy Court will reach the same conclusion.

We may have insufficient liquidity for our business operations during the Chapter 11 proceedings.

Although we believe that we will have sufficient liquidity to operate our businesses during the pendency of the Chapter 11 proceedings, there can be no assurance that the revenue generated by our business operations and cash made available to us under the cash collateral order or otherwise in our restructuring process will be sufficient to fund our operations, especially as we expect to incur substantial professional and other fees related to our restructuring. We have not made arrangements for financing in the form of a debtor-in-possession credit facility, or "DIP" facility. In the event that revenue flows and other available cash are not sufficient to meet our liquidity requirements, we may be required to seek additional financing. There can be no assurance that such additional financing would be available or, if available, offered on terms that are acceptable. If, for one or more reasons, we are unable to obtain such additional financing, we could be required to seek a sale of the company or certain of its material assets or our businesses and assets may be subject to liquidation under Chapter 7 of the Bankruptcy Code, and we may cease to continue as a going concern.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may not be successful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our ability to restructure our corporate organization, (iii) our ability to obtain adequate liquidity and financing sources, (iv) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (v) our ability to retain key employees and (vi) the overall strength and stability of general economic conditions in the global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, net income, debt service and cash flows. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure and our corporate structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

As a result of the Chapter 11 proceedings, realization of assets and liquidation of liabilities are subject to uncertainty.

While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.

As a result of the Chapter 11 proceedings, our historical financial information may not be indicative of our future financial performance.

Our capital structure and our corporate structure will likely be altered under any plan of reorganization ultimately confirmed by the Bankruptcy Court. Under fresh-start reporting rules that may apply to us upon the effective date of a plan of reorganization, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to nil. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 proceedings would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 proceedings and the development of a plan of reorganization, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to the consolidated financial position and results of operations in any given period.

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In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert the Chapter 11 proceedings to cases under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (1) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (2) additional administrative expenses involved in the appointment of a Chapter 7 trustee and (3) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation in connection with a cessation of operations.

Trading in our securities during the term of the Chapter 11 proceedings is highly speculative and poses substantial risks.

Trading in securities of an issuer in bankruptcy is extremely speculative, and there is a very significant risk that investors will lose all or a substantial portion of their investment. We can provide no assurances of recovery for holders of equity or that a plan will be confirmed and consummated, whether such certain circumstances will arise and the amount of any recoveries. Therefore it is impossible to predict at this time whether holders of our debt securities or our equity securities will receive any distribution with respect to, or be able to recover any portion of, their investments. Trading prices for our securities may bear little or no relationship to actual recovery, if any, by holders thereof during the term of the Chapter 11 proceedings.

We caution and urge existing and future investors to carefully consider the significant risks with respect to investments in our securities.

Risks Relating to Our Company and Our Business

The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition.

Our business depends on the level of oil and gas exploration, development and production in offshore areas worldwide that is influenced by oil and gas prices and market expectations of potential changes in these prices.

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including, but not limited to, the following:

•worldwide production of, and demand for, oil and gas and geographical dislocations in supply and demand;

•the cost of exploring for, developing, producing and delivering oil and gas;

•expectations regarding future energy prices and production;

•advances in exploration, development and production technology;

•the ability of the Organization of Petroleum Exporting Countries ("OPEC"), and other non-member nations, including Russia, to set and maintain levels of production and pricing;

•the decision of OPEC or other non-member nations to abandon production quotas and/or member-country quota compliance within OPEC agreements;

•the level of production in non-OPEC countries;

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

•government regulations, including restrictions on offshore transportation of oil and natural gas;

•local and international political, economic and weather conditions;

•domestic and foreign tax policies;

•the development and exploitation of alternative fuels and unconventional hydrocarbon production, including shale;

•worldwide economic and financial problems and the corresponding decline in the demand for oil and gas and, consequently, our services;

•the policies of various governments regarding exploration and development of their oil and gas reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and

•the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, Eastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.

Decreases in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have negatively affected and could continue to negatively affect our future performance. Brent bottomed out at $9 a barrel in April 2020 before a recovery in oil and gas prices towards the end of 2020 with Brent reaching $52 a barrel at December 31, 2020. However, there is no guarantee the price recovery will be sustained going forward and prices can fluctuate significantly in the future. While the outlook has improved substantially as a result of the development of effective vaccines and agreed production cuts between OPEC members and Russia, demand has recovered at a slower pace than initially expected, and demand levels remain significantly below those levels reached in late 2019 before the COVID-19 pandemic as the market continues to be oversupplied. Uncertainty remains around the timing and speed of a global economic recovery and therefore the timing of any increase in oil demand, although the Company anticipates some degree of market recovery by mid-2022. Since the supply of rigs in the market still outweighs demand there will continue to be a dampening effect on utilization levels and dayrates across all segments in 2021. However, the Company anticipates that it will continue to see accelerated retirement of older, and long-term stacked assets coupled with an expected increase in demand in late 2021, and this should go towards addressing the imbalance between demand and supply.

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Continued periods of low demand can cause excess rig supply and intensify competition in our industry, which often results in drilling rigs, particularly older and less technologically advanced drilling rigs, being idle for long periods of time. We cannot predict the future level of demand for drilling rigs or future conditions of the oil and gas industry with any degree of certainty. In response to the decrease in the prices of oil and gas, a number of our oil and gas company customers have announced significant decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could further reduce our revenues and materially harm our business.

In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, which could reduce demand for our services and adversely affect our business, including:

•the availability and quality of competing offshore drilling units;

•the availability of debt financing on reasonable terms;

•the level of costs for associated offshore oilfield and construction services;

•oil and gas transportation costs;

•the level of rig operating costs, including crew and maintenance;

•the discovery of new oil and gas reserves;

•the political and military environment of oil and gas reserve jurisdictions; and

•regulatory restrictions on offshore drilling.

The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, the condition and integrity of equipment, the rig's and/or the drilling contractor's record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics compared to our drilling rigs, or expand into service areas where we operate.

Competitive pressures and other factors may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition.

The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.

The oil and gas drilling industry is cyclical and is currently in a prolonged down cycle since 2014 and uncertainty remains around the timing and speed of any increase in oil demand, although the Company anticipates some degree of market recovery by mid-2022.

If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, we may idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items.

As of December 31, 2020, we had two "warm stacked" units, which means the rig is kept operational and ready for redeployment, and maintains most of its crew, and seven "cold stacked" units, which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed. Without new drilling contracts or additional financing being available when needed or available only on unfavorable terms, we will be unable to meet our obligations as they come due or we may be unable to enhance our existing business, complete additional drilling unit acquisitions or otherwise take advantage of business opportunities as they arise.

In the current environment, our customers may also seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, resulting in lower dayrates. Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

From time to time, we are approached by potential buyers for the outright purchase of some of our drilling units, businesses or other fixed assets. We may determine that such a sale would be in our best interests and agree to sell certain drilling units or other assets. Such a sale could have an impact on short-term liquidity and net income. We may recognize a gain or loss on disposal depending on whether the fair value of the consideration received is higher or lower than the carrying value of the asset.

We do not know when the market for offshore drilling units may recover, or the nature or extent of any future recovery. There can be no assurance that the current demand for drilling rigs will not further decline in future periods. The continued or future decline in demand for drilling rigs would adversely affect our financial position, operating results and cash flows.

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Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted

In the current market conditions, some of our customers may seek to terminate their agreements with us.

Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, such payments may not fully compensate us for the loss of the drilling contract.

Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of non-performance, periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond our control. In addition, national oil company customers may have special termination rights by law. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance.

Our customers may seek to renegotiate their contracts with us using various techniques, including threatening breaches of contract and applying commercial pressure, resulting in lower dayrates or the cancellation of contracts with or without any applicable early termination payments.

Reduced dayrates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) may adversely affect our performance and lead to reduced revenues from operations.

Our contract backlog for our fleet of drilling units may not be realized.

As of December 31, 2020, our contract backlog was approximately $46.8 million.

The contract backlog presented in this annual report and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned may be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, such as the current environment, resulting in lower dayrates. In some instances, there is an option for a customer to terminate a drilling contract prematurely for convenience on payment of an early termination fee. However, this fee may not adequately compensate us for the loss of this drilling contract.

Our inability, or the inability of our customers, to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts have expired or been terminated.

During the most recent period of high utilization and high dayrates, which we believe ended in early 2014, industry participants ordered the construction of new drilling units, which resulted in an over-supply and caused, in conjunction with deteriorating industry conditions, a decline in utilization and dayrates when the new drilling units entered the market. A relatively large number of the drilling units currently under construction have not been contracted for future work, and a number of units in the existing worldwide fleet are currently off-contract.

As of March 31, 2021, we have two drilling units on contract expiring in 2021. Our ability to renew these contracts or obtain new contracts will depend on our customers and prevailing market conditions, which may vary among different geographic regions and types of drilling units.

If we are unable to secure contracts for our drilling units we may continue to idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As at December 31, 2020 we had nine units either "warm stacked," which means the rig is kept operational and ready for redeployment, and maintains most of its crew, or "cold stacked," which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed.

If we are not able to obtain new contracts in direct continuation of existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and we may be unable to push this risk down to other contractors or be unable or unwilling at competitive prices to insure against this risk, which will mean the risk will have to be managed by applying other controls. This could lead to us being unable to meet our liabilities in the event of a catastrophic event on one of our rigs.

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The market value of our drilling units may further decrease.

The market values of drilling units have declined as a result of the recent continued decline in the price of oil, which has been impacted by the spending plans of our customers. If the offshore contract drilling industry suffers further adverse developments in the future, the fair market value of our drilling units may decline further. The fair market value of the drilling units that we currently own, or may acquire in the future, may increase or decrease depending on a number of factors, including:

•the general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;

•the types, sizes and ages of drilling units;

•the supply and demand for drilling units;

•the costs of newbuild drilling units;

•the prevailing level of drilling services contract dayrates;

•governmental or other regulations; and

•technological advances.

If drilling unit values fall significantly, we may have to record an impairment adjustment in our Consolidated Financial Statements, which could adversely affect our financial results and condition and cause us to breach covenants in our finance agreements.

Our business and operations involve numerous operating hazards, and in the current market we are increasingly required to take additional contractual risk in our customer contracts and we may not be able to procure insurance to adequately cover potential losses.

Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, cratering, fires, explosions and pollution. Contract drilling and well servicing requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third 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, damage from severe weather and marine life infestations. 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 claims relating to damage to or loss of our equipment, including rigs and claims relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property, environmental, natural resource,

personal injury and other damage claims by private parties, including oil and gas companies, as well as administrative, civil and criminal

penalties or injunctions by government authorities.

Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these customers will be willing or financially able to indemnify us against all these risks. Customers may seek to cap indemnities or narrow the scope of their coverage, reducing our level of contractual protection.

In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 decision in a case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act, or the "CWA," under a drilling contract governed by U.S. maritime law as a matter of public policy. Further, pollution and environmental risks generally are not totally insurable. If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our performance.

The amount recoverable under insurance may also be less than the related impact on enterprise value after a loss or not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs.

We could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts. Specifically, we have at times in the past elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico due to the substantial costs associated with such coverage. Beginning on April 1, 2014, we have insured a limited part of this windstorm risk in a combined single limit annual aggregate policy. We elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a combined single limit of $100 million in the annual aggregate, which includes loss of hire. If we elect to self-insure such risks again in the future and such windstorms cause significant damage to any rig and equipment we have in the U.S. Gulf of Mexico, it could have a material adverse effect on our financial position, results of operations or cash flows.

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No assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or that we will be able to obtain insurance against certain risks.

We derive the majority of our revenue from a small number of customers, and the loss of any of these customers could result in a material loss of revenues and cash flow.

We are subject to the risks associated with having a limited number of customers for our services. We currently derive the majority of our revenues and cash flow from a small number of customers. For the year ended December 31, 2020, BP, Reliance and ExxonMobil accounted for 75.8%, 8.6% and 8.3% of our total revenues, respectively. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services, or cancel or re-negotiate our contracts.

We are subject to risk of loss resulting from non-payment or non-performance by our customers and certain other third parties. Some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Any material non-payment or non-performance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.

Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including reactivation, operating and maintenance costs.

Our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. A significant portion of our operating costs may be fixed over the short term.

The majority of our contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, most of our long-term contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semiannually, and therefore may be outdated at the time of adjustment. The adjustments are typically performed on a semi-annual or annual basis. For these reasons, the timing and amount received as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance. In such contracts, the dayrate could be adjusted lower during a period when costs of operation rise, which could adversely affect our financial performance. Shorter-term contracts normally do not contain escalation provisions. In addition, our contracts typically contain provisions for either fixed or dayrate compensation during mobilization. These rates may not fully cover our costs of mobilization, and mobilization may be delayed, increasing our costs, without additional compensation from the customer, for reasons beyond our control.

In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. Expenses may vary based on a number of factors including the scope and length of such required preparations, whether the relevant unit is idle or stacked and reactivation is required and the duration of the contractual period over which such expenditures are amortized.

Equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment, as well as the applicable environmental, safety and maritime regulations and standards. Our operating expenses and maintenance costs depend on a variety of factors, including crew costs, provisions, equipment, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control.

In situations where our drilling units incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling units is limited, as the crews will be engaged in preparing the unit for its next contract. When a unit faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to redeploy crew members, who are not required to maintain the drilling unit, to active rigs, to the extent possible. However, there can be no assurance that we will be successful in reducing our costs in such cases.

Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services. Please see "The success and growth of our business depends on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition", "Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted" and "We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts which have expired or been terminated". This could adversely affect our revenue from operations.

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Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies

We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including, but not limited to, drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. With respect to certain items, such as blow-out preventers, we are dependent on the original equipment manufacturer for repair and replacement of the item or its spare parts. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. These cost increases or delays could have a material adverse effect on our results of operations and result in rig downtime, and delays in the repair and maintenance of our drilling rigs.

We may be unable to obtain, maintain, and/or renew permits necessary for our operations or experience delays in obtaining such permits including the class certifications of rigs

The operation of our drilling units is subject to certain governmental approvals, the number and prerequisites of which cannot be determined until we identify the jurisdictions in which we will operate on securing contracts for the drilling units. Depending on the jurisdiction, these governmental approvals 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 approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.

Every offshore drilling unit is a registered marine vessel and must be "classed" by a classification society to fly a flag. The classification society certifies that the drilling unit is "in-class," signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit's country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our drilling units are certified as being "in class" by the American Bureau of Shipping, or "ABS", Det Norske Veritas and Germanisher Lloyd, or "DNV GL," and the relevant national authorities in the countries in which our drilling units operate. If any drilling unit loses its flag, does not maintain its class, fails any periodical survey or special survey and/or fails to satisfy any laws of the country of operation, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable. Any such inability to carry on operations or be employed could have a material adverse impact on the results of operations.

The international nature of our operations involves additional risks including foreign government intervention in relevant markets.

We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, particularly in less developed jurisdictions, including risks of:

•terrorist acts, armed hostilities, war and civil disturbances;

•acts of piracy, which have historically affected ocean-going vessels;

•abduction, kidnapping and hostage situations;

•significant governmental influence over many aspects of local economies;

•the seizure, nationalization or expropriation of property or equipment;

•absence of laws or uncertainty of outcome in foreign court proceedings;

•the repudiation, nullification, modification or renegotiation of contracts;

•lack of cooperation with our due diligence or compliance practices;

•limitations on insurance coverage, such as war risk coverage, in certain areas;

•political unrest;

•foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;

•the inability to repatriate income or capital;

•complications associated with repairing and replacing equipment in remote locations;

•import-export quotas, wage and price controls, and the imposition of trade barriers;

•U.S., European Union and other foreign sanctions or trade embargoes;

•anti-boycott regulations;

•compliance with various jurisdictional regulatory or financial requirements;

•compliance with and changes in taxation;

•other forms of government regulation and economic conditions that are beyond our control; and

•governmental corruption.

In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:

•the equipping and operation of drilling units;

•exchange rates or exchange controls;

•the repatriation of foreign earnings;

•oil and gas exploration and development;

•the taxation of offshore earnings and the earnings of expatriate personnel; and

•the use and compensation of local employees and suppliers by foreign contractors.

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Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. 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, the denial of export privileges, injunctions or seizures of assets.

Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations.

Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.

Accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. For example, in 2015 and 2016, the United States President issued three Presidential Memoranda and an Executive Order withdrawing certain areas of the Outer Continental Shelf in the Atlantic Coast, Alaska and Arctic from mineral leasing under Section 12(a) of the Outer Continental Shelf Land Act, or “OCSLA.” Canada issued a similar ban on new drilling in Canadian Arctic waters in December 2016. President Trump issued Executive Order 13795 on April 28, 2017, directing the Department of the Interior to reconsider prior actions to limit or regulate offshore oil and gas development and revoking the 2015 and 2016 withdrawals. Environmental groups challenged the Executive Order and the U.S. District Court for the District of Alaska vacated the portion of the Executive Order rolling back the withdrawals; the Trump Administration appealed the decision to the Court of Appeals for the Ninth Circuit, which remains pending. On January 20, 2021, President Biden issued Executive Orders revoking Executive Order 13795 and pausing new oil and gas leasing in federal waters, including the Gulf of Mexico, pending a comprehensive review of the leasing program. In addition, environmental groups have challenged numerous lease sales offered by the Department of the Interior under the 2017-2022 five-year lease program and that litigation remains pending. As a result it is difficult to predict if and when such areas may be made available for future exploration activities. We may be required to make significant capital expenditures or operational changes to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity.

Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations.

The laws and regulations concerning import activity, export recordkeeping and reporting, 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. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from the failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, the seizure of shipments and the loss of import and export privileges.

Offshore drilling in certain areas, including arctic areas and the U.S. Gulf of Mexico, has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. New laws or other governmental actions 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 to the offshore drilling industry, in particular, could adversely affect our performance.

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 and production of oil and gas could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.

We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to the conventions under the auspices of the United Nation's International Maritime Organization, or the "IMO," the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended, or "MARPOL," including the designation of Emission Control Areas, or "ECAs" thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended, or the "CLC," the International Convention on Civil Liability for Bunker Oil Pollution Damage, or the "Bunker Convention," the International Convention for the Safety of Life at Sea of 1974, as from time to time amended, or "SOLAS," the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the "ISM Code," the IMO International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships' Ballast Water and Sediments in February 2004 or the "BWM Convention," the U.S. Oil Pollution Act of 1990, or the "OPA," requirements of the U.S. Coast Guard, or the "USCG," the U.S. Environmental Protection Agency, or the "EPA," the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or "CERCLA," the U.S. Maritime Transportation Security Act of 2002, or the "MTSA," the U.S. Outer Continental Shelf Lands Act, or "OCSLA," certain regulations of the European Union and the laws and regulations of other countries in which we operate. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or implementation of operational changes and may affect the resale value or useful lifetime of our drilling units. These costs could have a material adverse effect on our business, results

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of operations, cash flows and financial condition. 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. Because such conventions, laws and regulations are often revised, we cannot predict the ultimate cost of complying with them or the impact thereof on the resale prices or useful lives of our rigs. Additional conventions, laws and regulations may be adopted which could limit our ability to do business or increase the cost of our doing business and which may materially adversely affect our operations.

Certain environmental laws impose strict liability for the remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the 200-mile exclusive economic zone around the United States. An oil or chemical spill for which we are deemed a responsible party could result in us incurring significant liability, including fines, penalties, criminal liability and remediation costs for natural resource damages under other federal, state and local laws, as well as third-party damages, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further increased regulation of the shipping industry or modifications to statutory liability schemes, could expose us to further potential financial risk in the event of any such oil or chemical spill.

We are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to our operations, and satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. Although we have arranged insurance to cover certain environmental risks, there can be no assurance that such insurance will be sufficient to cover all such risks or that any claims will not have a material adverse effect on our business, results of operations, cash flows and financial condition.

Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.

Our drilling units could cause the release of oil or hazardous substances. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where environmental groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling rigs, clean up the releases and comply with more stringent requirements in our discharge permits. Moreover, these releases may expose us to private litigation or result in our customers or governmental authorities suspending or terminating our operations in the affected area(s), which could have a material adverse effect on our business, results of operations and financial condition.

If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable.

The insurance coverage we currently hold may not be available in the future, or we may not obtain certain insurance coverage. Furthermore, insurance costs may increase in the event of ongoing patterns of adverse changes in weather or climate. Even if insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities, or our insurance underwriters may be unable to pay compensation if a significant claim should occur. Any of these scenarios could have a material adverse effect on our business, results of operations and financial condition.

Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act 1977 or the UK Bribery Act 2010, could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.

We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. We interact with government regulators, licensor's, port authorities and other government entities and officials. Also, our business interaction with national oil companies as well as state or government-owned shipbuilding enterprises and financing agencies puts us in contact with persons who may be considered to be "foreign officials" under the FCPA and UK Bribery Act. We are subject to the risk that we or our affiliated companies or their respective officers, directors, employees and agents may take actions determined to be in violation of anti-corruption laws, including the FCPA and the U.K. Bribery Act. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

In order to effectively compete in some foreign jurisdictions, we utilize local agents and/or establish entities with local operators or strategic partners. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violations of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business and results of operation.

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If our drilling units are located in countries that are subject to or targeted by economic sanctions, export restrictions or other operating restrictions imposed by the United States, the United Kingdom, European Union or other governments, our reputation and the market for our debt and common units could be adversely affected.

The U.S., the U.K., European Union and other governments impose economic sanctions against certain countries, persons and other entities that restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran and others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. U.S., U.K., European Union and other economic sanctions change frequently and enforcement of economic sanctions worldwide is increasing.

In 2010, the United States enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or "CISADA," which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours, and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the "Iran Threat Reduction Act," which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose in their annual and quarterly reports filed with the Commission after February 6, 2013 if the issuer or "any affiliate" has "knowingly" engaged in certain sanctioned activities involving Iran during the timeframe covered by the report. At this time, we are not aware of any violation conducted by us or by any affiliate, which is likely to trigger such a disclosure requirement.

On November 24, 2013, the United States, United Kingdom, Germany, France, Russia and China, or the "P5+1," entered into an interim agreement with Iran entitled the "Joint Plan of Action," or the "JPOA." Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is only used for peaceful purposes, the United States and the European Union would voluntarily suspend certain sanctions for a period of six months. On January 20, 2014, the United States and the European Union began implementing the temporary relief measures provided for under the JPOA.

The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the European Union, at the time including the U.K., announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran's Nuclear Program, or the "JCPOA," to significantly restrict Iran's ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and not involving U.S. persons. On January 16, 2016, or the Implementation Day, the United States joined the European Union and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the "IAEA," that Iran had satisfied its respective obligations under the JCPOA.

U.S. sanctions prohibiting certain conduct that were permitted under the JCPOA were not actually repealed or permanently terminated at the time. Rather, the U.S. government had implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders.

On October 13, 2017, the current U.S. administration announced it would not certify Iran's compliance with the JCPOA. This did not withdraw the U.S. from the JCPOA or re-instate any sanctions. However, they have criticized the JCPOA and threatened to withdraw the U.S. from the JCPOA. Further, the administration must periodically renew sanction waivers and his refusal to do so could result in the reinstatement of certain sanctions currently suspended under the JCPOA.

OFAC acted several times in 2017 to add Iranian individuals and entities to its list of Specially Designated Nationals ("SDN List") whose assets are blocked and with whom U.S. persons are generally prohibited from dealing. Moreover, in August 2017, the U.S. passed the "Countering America's Adversaries Through Sanctions Act" (Public Law 115-44) ("CAATSA"), which authorizes imposition of new sanctions on Iran, Russia, and North Korea. The CAATSA sanctions with respect to Russia create heightened sanctions risks for companies operating in the oil and gas sector, including companies that are based outside of the United States. Additionally, in December 2019, the U.S. passed as part of the National Defense Authorization act for Fiscal Year 2020 ("NDAA 2020") new sanctions measures targeting North Korea, Syria, Turkey, and firms constructing and investing in the Nord Stream 2 undersea gas pipeline in the Baltic Sea. As per the requirements of the NDAA 2020, the U.S. Department of State, in coordination with U.S. Department of the Treasury, will identify the specific firms by February 2020.

On May 8, 2018, the U.S. announced it was ending its participation in the JCPOA, and began to take steps to re-impose economic sanctions broadly targeting the Iranian economy. OFAC announced that sanctions that had been lifted under the JCPOA would be re-instated after a wind-down period, some on August 6, 2018, and others on November 4, 2018. The announcement largely did not establish new sanctions on Iran, but re-imposed in concrete fashion, sanctions that had been revoked previously. Notably, at the end of the wind down period, hundreds of Iranian counterparties whose sanctioned status had been lifted pursuant to the JCPOA were once again formally designated by the U.S. government as restricted parties. Also, at the end of the wind-down period, OFAC revoked the general authorization ("General License H") which allowed non-U.S. companies owned or controlled by U.S. companies to engage in certain business with Iran. Since the U.S. withdrew from the JCPOA, OFAC has, on several occasions in 2019 and 2020, added Iranian and other individuals and entities to the SDN List, while issuing further advisories on Iran sanctions risks, particularly when acting within or parallel to the maritime petroleum shipping industry. Further, OFAC issued sanctions on specific sectors of the Iranian economy, including the iron, steel, aluminum and copper sectors (May 8,

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2019), the construction, mining, manufacturing or textiles sectors (January 10, 2020), and the financial sector (October 8, 2020). These sector-wide sanctions also authorize the imposition of secondary sanctions on non-U.S. persons and non-U.S. financial institutions who engage in certain dealings in those sectors, including the potential designation of such persons or financial institutions themselves.

OFAC sanctions targeting Venezuela have likewise increased throughout 2018 and 2019. In 2018, OFAC issued sanctions prohibiting U.S. persons transacting with certain financial services or debt instruments affiliated with Venezuela or its government. Additionally, between November 2018 and May 2019, OFAC issued sanctions on a number of sectors of the Venezuelan economy including the oil sector, as well as the gold, financial and defense/security sectors while adding Venezuelan and other affiliated individuals and entities to the SDN List.

On January 28, 2019, OFAC added Petroleos de Venezuela, S.A., the Venezuela state-owned oil company, to the SDN List, and prohibited U.S. persons from transacting with it and its subsidiaries (e.g. CITGO Holding, Inc., ("CITGO") and PDV Holding, Inc. ("PDVH")). Through a series of general licenses (currently Venezuela General License 2A and Venezuela General License 7C), some of which are temporary, the U.S. government authorized transactions involving CITGO and PDVH that would otherwise be prohibited. To further expand the sanctions on Venezuela, the President issued Executive Order 13884 on August 5, 2019 that added the government of Venezuela itself to the SDN List, and sanctioned all entities owned or controlled by, or to have acted or purported to act for or on behalf of, directly or indirectly the government of Venezuela. OFAC has also imposed sanctions on non-Venezuelan firms for operating in Venezuela. On February 18, 2020, OFAC imposed sanctions on Switzerland-based firm Rosneft Trading S.A., due to its operations in the oil sector of Venezuela. On November 30, 2020, OFAC imposed sanctions on the Chinese state owned entity China National Electronics Imports and Export Corporation for providing support to Venezuela government entities.

In addition to the sanctions against Iran, subject to certain limited exceptions, U.S. law continues to restrict U.S. owned or controlled entities from doing business with Cuba and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing and enforcing sanctions regimes.

On December 14, 2020, the United States Department of State rescinded its designation of Sudan as a State Sponsor of Terrorism, and on January 14, 2021, the U.S. Department of Commerce effectuated the change resulting in certain items being eligible for export to Sudan and export license exceptions being applicable for exports to Sudan.

On December 18, 2020, the U.S. Department of Commerce Bureau of Industry and Security (“BIS”) designated a number of Chinese parties on the Entity List, including parties involved in the offshore drilling and maritime industries such as China Communications Construction Company Ltd. Most items subject to the Export Administration Regulations (“EAR”) now require a license to export or re-export to such parties. On January 14, 2021, BIS added Chinese National Offshore Oil Corporation to the Entity List. On December 23, 2020, BIS also established a Military End User List (“MEUL”) and designated over 100 parties from China and Russia on the MEUL, including those in the offshore drilling and maritime industries. Certain items subject to the EAR require a license from BIS to export or re-export to such parties.

On February 11, 2021 President Biden signed Executive Order 14014 Blocking Property with Respect to the Situation in Burma (Myanmar) imposing sanctions on individuals associated with the Myanmar military, followed thereafter by OFAC adding certain individuals and companies to the SDN List on that basis. On February 11, 2021 BIS announced that it would apply a presumption of denial for items requiring a license for export to select Myanmar government agencies. On March 4, 2021 BIS added certain Myanmar government agencies to the Entity List and imposed restrictions on exports and reexports to Myanmar, to military end users and for military end uses comparable to the restrictions imposed on such persons in China, Russia, and Venezuela. On March 25, 2021 OFAC added to the SDN List Myanmar Economic Holdings Public Company Limited and Myanmar Economic Corporation Limited, on the basis these two military holding companies dominate certain sectors of Myanmar’s economy, including natural resources.

From time to time, we may enter into drilling contracts with countries or government-controlled entities that are subject to sanctions, export restrictions, and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism where entering into such contracts would not violate U.S. law, or may enter into drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism. However, this could negatively affect our ability to obtain investors. In some cases, U.S. investors would be prohibited from investing in an arrangement in which the proceeds could directly or indirectly be transferred to or may benefit a sanctioned entity. Moreover, even in cases where the investment would not violate U.S. law, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our common units.

Certain parties with whom we have entered into contracts may be the subject of sanctions imposed by the United States, the European Union or other international bodies as a result of the annexation of Crimea by Russia in March 2014 and the subsequent conflict in eastern Ukraine, or may be affiliated with persons or entities that are the subject of such sanctions. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected or we may suffer reputational harm.

As stated above, we believe that we are in compliance with all applicable economic sanctions and embargo laws and regulations, and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Rapid changes in the scope of global sanctions may also make it more difficult for us to remain in compliance. Any violation of applicable economic sanctions could result in civil or criminal penalties, fines, enforcement actions, legal costs, reputational damage or other penalties and could result in some investors deciding, or being required, to

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divest their interest, or not to invest, in our common units. Additionally, some investors may decide to divest their interest, or not to invest, in our common units simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our drilling rigs, and those violations could in turn negatively affect our reputation. Investor perception of the value of our common units may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

A continuing economic downturn could have a material adverse effect on our revenue, profitability and financial position.

We depend on our customers' willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain European countries and their ability to meet future financial obligations and the overall stability of the Euro. Further, the COVID-19 outbreak that began in December 2019 was declared a global pandemic on March 11, 2020 by the World Health Organization. The COVID-19 outbreak has had numerous effects on the global economy and has caused a global economic downturn. While there are some signs of an economic recovery, economic activity is still depressed as a result of continuing restrictions in response to the pandemic and high levels of unemployment and associated economic uncertainty. A renewed period of adverse development in the outlook for the financial stability of European countries, or market perceptions concerning these and related issues, could reduce the overall demand for oil and natural gas and for our services and thereby could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in the Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.

Negative developments in worldwide financial and economic conditions could further cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, lenders willingness to provide credit facilities to our customers, causing them to fail to meet their obligations to us.

A portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.

On June 23, 2016, the U.K. held a referendum in which voters approved an exit from the E.U., commonly referred to as “Brexit”. The U.K.’s withdrawal from the E.U. occurred on January 31, 2020, but the U.K. remained in the E.U.’s customs union and single market for a transition period that expired on December 31, 2020. On December 24, 2020, the U.K. and the E.U. entered into a trade and cooperation agreement (the “Trade and Cooperation Agreement”), which was applied on a provisional basis from January 1, 2021. While the economic integration does not reach the level that existed during the time the U.K. was a member state of the E.U., the Trade and Cooperation Agreement sets out preferential arrangements in areas such as trade in goods and in services, digital trade and intellectual property. Negotiations between the U.K. and the E.U. are expected to continue in relation to the relationship between the U.K. and the E.U. in certain other areas which are not covered by the Trade and Cooperation Agreement. The long-term effects of Brexit will depend on the effects of the implementation and application of the Trade and Cooperation Agreement and any other relevant agreements between the United Kingdom and the European Union.

An extended period of adverse development in the outlook for the world economy could also reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices.

Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund our capital expenditures. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations or interpretations thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.

Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic or deepwater locations, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, concentrating drilling units in regions with relatively fewer reductions in activity leading to greater competition.

If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing when required.

Our ability to operate our drilling units in the U.S. Gulf of Mexico could be impaired by governmental regulation, particularly in the aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout.

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In the aftermath of the Deepwater Horizon Incident (in which we were not involved), various governmental agencies, including the U.S. Department of the Interior, or "DOI," U.S. Bureau of Safety and Environmental Enforcement ("BSEE") and its predecessor, the U.S. Bureau of Ocean Energy Management ("BOEM"), and the U.S. Occupational Safety and Health Administration issued new and revised regulations and guidelines governing environmental protection, public and worker health and safety, financial assurance requirements, inspection programs and other well control measures relating to our drilling rigs.

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 previously 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 relating to the design, maintenance, installation and testing of well control equipment. Current and pending regulations, guidelines and standards for safety, environmental and financial assurance, such as the above, and any other new guidelines or standards the U.S. government or industry may issue (including relating to catastrophic events involving pollution from oil exploration and development activities) or any other steps the U.S. government or industry may take relating to our business activities, 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 U.S. and non-U.S. offshore areas.

As new standards and procedures are being integrated into the existing framework of offshore regulatory programs, there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as re-completions, workovers and abandonment activities.

We are not able to predict the likelihood, nature or extent of additional rule making or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling units in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. Additional governmental regulations concerning leasing, licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for our services. In addition, insurance costs across the industry have increased as a result of the Deepwater Horizon Incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all. We cannot predict the potential impact of new regulations that may be forthcoming, nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, our cash flow and financial position could be adversely affected if our ultra-deepwater semi-submersible drilling rigs and ultra-deepwater drillships operating in the U.S. Gulf of Mexico were subject to the risks mentioned above.

In addition, hurricanes have from time to time caused damage to a number of drilling units and production facilities unaffiliated to us in the U.S. Gulf of Mexico. BOEM and BSEE, have in recent years issued more stringent guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, moored drilling unit fitness, as well as other guidelines and regulations in an attempt to increase the likelihood of the survival of offshore drilling units during a hurricane. Implementation of new guidelines or regulations that may apply to our drilling units may subject us to increased costs and limit the operational capabilities of our drilling units.

Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.

We require highly skilled personnel in the right locations to operate and provide technical services and support for our business.

Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased, and this may continue to rise. Notwithstanding the general downturn in the drilling industry, in some regions, such as Western Africa, the limited availability of qualified personnel in combination with local regulations focusing on crew composition, are expected to further increase the demand for qualified offshore drilling crews, which may increase our costs. These factors could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.

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 for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. Any such downtime or cancellation could adversely affect our financial condition, results of operations and ability to make distributions to our unitholders.

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Climate change and the regulation of greenhouse gases could have a negative impact on our business.

Due to concern over the risk of climate change, a number of countries and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions, or "GHGs." Currently, the emissions of GHGs from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force on February 16, 2005 and pursuant to which adopting countries have been required to implement national programs to reduce GHG emissions. Additionally, emissions from international shipping are not subject to the Paris Agreement, which resulted from the 2015 United Nations Framework Convention on Climate Change conference in Paris and entered into force on November 4, 2016. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted in July 2011 by the IMO's Maritime Environment Protection Committee, or the "MEPC," relating to GHG emissions. A roadmap for developing a "comprehensive IMO strategy on reduction of GHG emissions from ships" was also approved by MEPC at its 70th session in October 2016. In April 2018, as the first milestone in the roadmap, the MEPC adopted an "initial IMO strategy on reduction of GHG emissions from ships" which aims to reduce the total annual GHG emissions from international shipping by at least 50% by 2050 compared to 2008, among other goals. The next milestone of the roadmap is adoption in 2023 of a revised strategy to reduce GHG emissions from ships. These and any future requirements could cause us to incur additional compliance costs.

In addition, the European Union has indicated that it may propose in the future an expansion of the existing European Union Emissions Trading Scheme to include GHG emissions from marine vessels. In April 2015, a regulation was adopted requiring that large ships (over 5,000 gross tonnes) calling at European Union ports from January 2018 collect and publish data on carbon dioxide emissions and other information. In the United States, the EPA, has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit GHG emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to GHG emissions from drilling units, the EPA has received petitions from the California Attorney General and various environmental groups seeking such regulation. Separately, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector; although, in September 2020, the EPA finalized amendments that relaxed or rescinded the rules. On January 20, 2021, President Biden issued an Executive Order directing the EPA to consider revising or rescinding the 2019 rules. Additionally, the United States Congress has considered legislation to reduce emissions of GHGs and many states and regions have already taken legal measures to reduce or measure GHG emission levels, often involving the planned development of GHG emission inventories and/or regional cap and trade programs.

Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our assets, and might also require us to install new emission controls, acquire allowances or pay taxes related to our GHG emissions, or administer and manage a GHG emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol or Paris agreement, could require us to make significant financial expenditures which we cannot predict with certainty at this time.

Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for the use of alternative energy sources. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in or lending to oil and gas activities. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business, including capital expenditures to upgrade our drilling rigs, which we cannot predict with certainty at this time. Finally, growing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce significant physical effects, such as increased frequency and severity of storms, hurricanes and other climatic events. In particular, certain areas in and near the U.S. Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our assets in the U.S. Gulf of Mexico are susceptible to damage and/or total loss by these storms. High winds and turbulent seas could also result disruptions in our operations due to damage to other related facilities in the area. If any such effects were to occur, they could have a significant financial and operational adverse impact on our business or cause us to incur significant costs in preparing or responding to those effects.

We face various risks associated with increased activism against oil and natural gas exploration and development activities.

Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as offshore drilling and development. For example, environmental activists have recently challenged lease sales, seismic acquisition activities and decisions to grant air quality permits in the U.S. Gulf of Mexico for offshore drilling and have challenged permitting and lease sales in the Arctic National Wildlife Refuge in Alaska. Certain financial institutions, funds and other sources of capital have, as a result, restricted or eliminated their investment in or lending to oil and gas activities.

Acts of terrorism, piracy, cyber-attacks, political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.

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Acts of terrorism, piracy, and political 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. Our drilling operations could also be targeted by acts of sabotage carried out by environmental activist groups.

We rely on information technology systems and networks in our operations and administration of our business. Our drilling operations or other business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to an unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.

In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.

We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.

The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over an infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services or replacement parts, or could be required to cease using some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of these technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have indemnity provisions in some of our supply contracts to give us some protection from the supplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will have sufficient financial standing to honor their indemnity obligations, or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes. For information on certain intellectual property litigation that we are currently involved in, please see Item 8 - "Financial Information - Consolidated Statements and Other Financial Information - Legal Proceedings".

The failure to consummate or integrate acquisitions in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.

We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Under the Omnibus Agreement, subject to certain exceptions, Seadrill is obligated to offer to us any of its drilling units acquired or placed under drilling contracts of five or more years. Although we are not obligated to purchase any of these drilling units offered by Seadrill, any acquisition could involve the payment of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain acquisition and investment opportunities may not result in the consummation of a transaction. In addition, we may not be able to obtain acceptable terms for the required financing for any such acquisition or investment that arises. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of its common units. Our future acquisitions could present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management's attention from existing operations or other priorities. We may also be subject to additional costs related to compliance with various international laws in connection with such acquisition. If we fail to consummate and integrate our acquisitions in a timely and cost-effective manner, its financial condition, results of operations and cash available for distribution could be adversely affected.

Public health threats, such as the coronavirus, or COVID-19, outbreak could have an adverse effect on our operations and financial results.

Public health threats, such as Ebola, influenza, Severe Acute Respiratory Syndrome ("SARS"), the Zika virus, COVID-19 and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world in which we operate, could adversely impact our operations and the operations of our customers. For example, the outbreak of COVID-19 has been declared by the World Health Organization as a pandemic and has spread across the globe to many countries in which we do business and is impacting worldwide economic activity. Public health threats in any area, including areas where we do not operate, could disrupt international transportation. Our crews generally work on a rotation basis, with a substantial portion relying on international air transport for rotation. Any disruptions could impact the cost of rotating our crews, and possibly impact our ability to maintain a full crew on all rigs at a given time. We continue to evaluate the impact that COVID-19 could have on our business. The continued spread of COVID-19, the measures taken by the governments of countries affected, actions taken to protect employees, and the impact of the pandemic on various business activities in affected countries and any other public health threats and related consequences could adversely affect our financial condition, results of operations and cash flows.

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Risks Relating to an Investment in our Units

Our filing for Chapter 11 protection within the US Bankruptcy Code could result in a significant reduction or elimination of current shareholder positions.

We and a substantial number of our consolidated subsidiaries filed voluntary petitions for relief under Chapter 11. This was part of our previously announced efforts to re-align our balance sheet to current market conditions by materially reducing our overall level of indebtedness. The filing for Chapter 11 provides a platform with respect to a comprehensive restructuring of our debt under Chapter 11 proceedings. The outcome of this process and future capital structure remain in negotiation. It is likely to involve significant equitization of debt and thereby material reductions to current unitholders positions. Accordingly investors may lose part or the full value of their investments.

Our common units are currently traded on the OTC Pink Market, which could adversely affect the market liquidity of our common units and harm our business.

Our common units currently trade on the over-the-counter market ("OTC") under the ticker symbol "SDLPQ."

The OTC Pink Market is an over-the-counter market that is a significantly more limited market than the NYSE. Securities traded on the OTC markets are usually thinly traded, highly volatile, have fewer market makers and are not followed by analysts. Trading on the OTC Pink Market or one of the other OTC markets may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

•the volume and liquidity of our common units;

•the market price of our common units;

•our ability to raise additional financing through public or private sales of equity securities or obtain other financing;

•the number of institutional and other investors that will consider investing in our common units;

•the number of market makers in our common units;

•the availability of information concerning the trading prices and volume of our common units; and

•the number of broker-dealers willing to execute trades in our common units.

Further, since our common units were delisted from the NYSE, we are subject to fewer rules and regulations, including with respect to corporate governance and the providing of certain financial information, than if our common units were traded on the NYSE. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

The market price of our common units has fluctuated widely and may fluctuate widely in the future.

The market price of our common units has fluctuated widely and may continue to do so as a result of many factors, such as actual or anticipated fluctuations in our operating results, changes in our distributions to unitholders, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Further, there may be no continuing active or liquid public market for our common units. If an active trading market for our common units does not continue, the price of our common units may be more volatile and it may be more difficult and time consuming to complete a transaction in the common units, which could have an adverse effect on the realized price of the common units. In addition, an adverse development in the market price for our common units could negatively affect our ability to issue new equity to fund our activities. For our common unit price history, refer Item 9 - "The Offer and Listing - A. Offer and Listing Details".

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.

Because our ownership interest in OPCO currently represents our only cash-generating asset, our cash flow depends completely on OPCO's ability to make distributions to its owners, including us.

Our cash flow depends completely on OPCO's distributions to us. The amount of cash OPCO distributes may fluctuate from quarter to quarter based on our operational and financial performance which is subject to the risk factors set out above, "Risks Relating to our Company".

The actual amount of cash OPCO has available for distribution also depends on our cash flow which is subject to the risk factors set out above, "Risks Relating to our Company".

OPCO's operating agreements provide that it will distribute its available cash to its owners on a quarterly basis. OPCO's available cash includes cash on hand less any reserves that may be appropriate for operating its business. The amount of OPCO's quarterly distributions, including the amount of cash reserves not distributed, is determined by our Board.

The amount of cash OPCO generates from operations may differ materially from its profit or loss for the period, which is affected by non-cash items. As a result of this and the other factors mentioned above, OPCO may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.

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We may not pay distributions in the future including the minimum quarterly distribution on common units and subordinated units.

The source of our earnings and cash flow consists exclusively of cash distributions from OPCO. Therefore, the amount of cash distributions we are able to make to our unitholders fluctuates, based on the level of distributions made by OPCO to its owners, including us, and the level of cash distributions made by OPCO's operating subsidiaries to OPCO. OPCO or any such operating subsidiaries may make quarterly distributions at levels that will not permit us to make distributions to our common unitholders at the minimum quarterly distribution level or to increase our quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if OPCO increases or decreases distributions to us, the timing and amount of any such increased or decreased distributions will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by OPCO to us.

Our ability to distribute to unitholders any cash we may receive from OPCO or any future operating subsidiaries is or may be limited by a number of factors, including, among others:

•interest expense and principal payments on any indebtedness we may incur;

•restrictions on distributions contained in any of our current or future debt agreements;

•fees and expenses of us, the Seadrill Member, its affiliates or third parties we are required to reimburse or pay; and

•reserves the Board believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

Many of these factors will reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we make may not be at or above the minimum quarterly distribution. For example, beginning in February 2016, we ceased paying distributions on the subordinated units, and in January 2020, we ceased paying distributions on the common units. The actual amount of cash that is available for distribution to our unitholders depends on several factors, many of which are beyond our control.

Our level of debt and restrictions in our debt agreements may prevent us from paying distributions.

The payment of principal and interest on our debt will reduce cash available for distribution to us and our unitholders. Our and OPCOs financing agreements contain restrictions on our or OPCO's ability to pay distributions to our unitholders or to us, respectively, under certain circumstances. In addition, our financing agreements contain provisions that, upon the occurrence of certain events, permit lenders to terminate their commitments and/or accelerate the outstanding loans and declare all amounts due and payable, which may prevent us from paying distributions to our unitholders.

Any adverse change in the level of risk to us of exogenous factors influencing our performance could prevent us from paying distributions including, but not limited to, economic conditions in both the industry and the world, legislation in different jurisdictions, interest rates and levels of taxation. Please see "Risks Relating to our Company".

Restrictions under Marshall Islands law may prevent us from paying distributions.

We or OPCO may be unable to pay distributions due to restrictions under Marshall Islands law. Under the Marshall Islands Limited Liability Company Act of 1996 (the "Marshall Islands Act"), we may not make a distribution to our unitholders if, after giving effect to the distribution, all our liabilities, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to our specified property, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of our property exceeds that liability. Identical restrictions exist on the payment of distributions by OPCO to its equity holders. Moreover, our subsidiaries that are not organized in the Marshall Islands and are subject to certain restrictions on payment of distributions pursuant to the law of their jurisdictions of organization.

Our common unitholders have limited voting rights compared to the Seadrill Member, who may favor its own interests to the detriment of the common unitholders.

As of March 31, 2021, Seadrill owned 34.9% of our common units and 100% of our subordinated units, and owned and controlled the Seadrill Member. Certain of our officers and directors are directors and/or officers of Seadrill and its subsidiaries and, as such, they have fiduciary duties to Seadrill that may cause them to pursue business strategies that disproportionately benefit Seadrill or which otherwise are not in the best interests of us or our unitholders. Conflicts of interest may arise between Seadrill and its subsidiaries on the one hand, and us and our unitholders, on the other hand. Although a majority of our Board is elected by common unitholders, the Seadrill Member will likely have substantial influence on decisions made by the Board. Refer to Item 7 - "Major Unitholders and Related Party Transactions - B. Related Party Transactions".

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These conflicts include, among others, the following situations:

•neither our operating agreement nor any other agreement requires the Seadrill Member or Seadrill or its affiliates to pursue a business strategy that favors us or utilizes our assets, and Seadrill's officers and directors have a fiduciary duty to make decisions in the best interests of the shareholders of Seadrill, which may be contrary to our interests;

•our operating agreement provides that the Seadrill Member may make determinations to take or decline to take actions without regard to the interests of us or our unitholders. Specifically, the Seadrill Member may exercise its call right, pre-emptive rights, registration rights or right to make a determination to receive common units in exchange for resetting the target distribution levels related to the incentive distribution rights, consent or withhold consent to any merger or consolidation of us, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our operating agreement that require a vote of the outstanding units, voluntarily withdraw from us, transfer (to the extent permitted under our operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon our dissolution;

•the Seadrill Member and our directors and officers have limited their liabilities and any fiduciary duties they may have under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders, and, as a result of purchasing common units, unitholders are treated as having agreed to the modified standard of fiduciary duties and to certain actions that may be taken by the Seadrill Member and our directors and officers, all as set forth in the operating agreement;

•the Seadrill Member is entitled to reimbursement of all costs incurred by it and its affiliates for our benefit;

•our operating agreement does not restrict us from paying the Seadrill Member or its affiliates for any services rendered to us on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities;

•the Seadrill Member may exercise its right to call and purchase our common units if it and its affiliates own more than 80% of our common units; and

•the Seadrill Member is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of its limited call right.

The resolution of these conflicts may conflict with our interests and the interests of our unitholders.

Although we control OPCO, we owe duties to OPCO and its other owner, Seadrill, which may conflict with our interests and the interests of our unitholders.

Conflicts of interest may arise because of the relationships between us and our unitholders, on the one hand, and OPCO, and its other owner, Seadrill, on the other hand. Seadrill owns a 42% limited partner interest in Seadrill Operating LP, a 49% limited liability company interest in Seadrill Capricorn Holdings LLC and a 100% limited liability company interest in the Seadrill Member. Our directors have duties to manage OPCO in a manner beneficial to us. At the same time, our directors have a duty to manage OPCO in a manner beneficial to OPCO's owners, including Seadrill. For example, conflicts of interest may arise in the following situations:

•the allocation of shared overhead expenses between us and OPCO;

•the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and OPCO or its subsidiaries, on the other hand;

•the determination and timing of the amount of cash to be distributed to OPCO's owners and the amount of cash to be reserved for the future conduct of OPCO's business;

•the decision as to whether OPCO should make asset or business acquisitions or dispositions, and on what terms;

•the determination of the amount and timing of OPCO's capital expenditures;

•the determination of whether OPCO should use cash on hand, borrow or issue equity to raise cash to finance maintenance or expansion capital projects, repay indebtedness, meet working capital needs or otherwise; and

•any decision we make to engage in business activities independent of, or in competition with, OPCO.

The resolution of these conflicts may conflict with our interests and the interests of our unitholders.

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Our operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Seadrill Member, and even if public unitholders are dissatisfied, they will be unable to remove the Seadrill Member without Seadrill's consent, unless Seadrill's ownership interest in us is decreased; all of which could diminish the trading price of our common units.

Our operating agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Seadrill Member.

•The unitholders are unable to remove the Seadrill Member without its consent because the Seadrill Member and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove the Seadrill Member. As of March 31, 2021, Seadrill owned 35% of the outstanding common units.

•If the Seadrill Member is removed without "cause" during the subordination period and units held by the Seadrill Member and Seadrill are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units, any existing arrearages on the common units will be extinguished, and the Seadrill Member will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. A removal of the Seadrill Member under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we have met certain distribution and performance tests. Any conversion of the Seadrill Member interest or incentive distribution rights would be dilutive to existing unitholders. Furthermore, any cash payment in lieu of such conversion could be prohibitively expensive. "Cause" is narrowly defined to mean that with respect to a director or officer, a court of competent jurisdiction has entered a final, non-appealable judgment finding such director or officer liable for actual fraud or willful misconduct, and with respect to the Seadrill Member, the Seadrill Member is in breach of the operating agreement or a court of competent jurisdiction has entered a final, non-appealable judgment finding the Seadrill Member liable for actual fraud or willful misconduct against us or our members, in their capacity as such. Cause does not include most cases of charges of poor business decisions, such as charges of poor management of our business by the directors appointed by the Seadrill Member, so the removal of the Seadrill Member because of the unitholders' dissatisfaction with the Seadrill Member's decisions in this regard would most likely result in the termination of the subordination period.

•Common unitholders are entitled to elect up to four of the members of the Board. The Seadrill Member in its sole discretion appoints the remaining three directors.

•Election of the four directors elected by unitholders is staggered, meaning that the members of only one of three classes of our elected directors are selected each year. In addition, the directors appointed by the Seadrill Member serve for terms determined by the Seadrill Member.

•Our operating agreement contains provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about our operations as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

•Unitholders' voting rights are further restricted by the operating agreement provision providing that if any person or group owns beneficially more than 5% of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board are not subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.

•There are no restrictions in our operating agreement on our ability to issue additional equity securities.

The effect of these provisions may be to diminish the price at which the common units trade.

In establishing cash reserves, the Board may reduce the amount of cash available for distribution to the unitholders.

OPCO's operating agreement provides that we approve the amount of reserves from OPCO's cash flow that will be retained by OPCO to fund its future operating and capital expenditures. Our operating agreement requires the Board to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating and capital expenditures. These reserves also affect the amount of cash available for distribution by OPCO to us, and by us to unitholders. In addition, the Board may establish reserves for distributions on the subordinated units, but only if those reserves do not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. Our operating agreement requires the Board each quarter to deduct from operating surplus estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, which could reduce the amount of available cash for distribution. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by the Board at least once a year, provided that any change must be approved by the conflicts committee of the Board.

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Unitholders have limited voting rights, and our operating agreement restricts the voting rights of the unitholders owning more than 5% of our common units.

Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. We hold a meeting of the members every year to elect one or more members of the Board and to vote on any other matters that are properly brought before the meeting. Common unitholders are entitled to elect only four of the seven members of the Board. The elected directors are elected on a staggered basis and serve for three-year terms. The Seadrill Member in its sole discretion appoints the remaining three directors and sets the terms for which those directors will serve. The operating agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management. Unitholders have no right to elect the Seadrill Member, and the Seadrill Member may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding common and subordinated units, including any units owned by the Seadrill Member and its affiliates, voting together as a single class.

Our operating agreement further restricts unitholders' voting rights by providing that if any person or group owns beneficially more than 5% of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes, unless required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board are not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.

Our operating agreement may limit the duties of the Seadrill Member and our directors and officers to our unitholders and restricts the remedies available to our unitholders for actions taken by the Seadrill Member or our directors and officers.

Our operating agreement provides that the Board has the authority to oversee and direct our operations, management and policies on an exclusive basis. The Marshall Islands Act states that a member's or manager's "duties and liabilities may be expanded or restricted by provisions in a limited liability company agreement." As permitted by the Marshall Islands Act, our operating agreement contains provisions that reduce the standards to which the Seadrill Member and our directors and officers may otherwise be held by Marshall Islands law. For example, our operating agreement:

•provides that the Seadrill Member may make determinations or take or decline to take actions without regard to the interests of us or our unitholders. The Seadrill Member may consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or our unitholders. Decisions made by the Seadrill Member are made by its sole owner, Seadrill. Specifically, the Seadrill Member may decide to exercise its right to make a determination to receive common units in exchange for resetting the target distribution levels related to the incentive distribution rights, call right, pre-emptive rights or registration rights, consent or withhold consent to any merger or consolidation, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our operating agreement that require a vote of the outstanding units, voluntarily withdraw from us, transfer (to the extent permitted under our operating agreement) or refrain from transferring its units, the Seadrill Member interest or incentive distribution rights or vote upon our dissolution;

•provides that the Board and officers are entitled to make other decisions in "good faith," meaning they believe that the decision is in our best interests;

•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," the Board may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•provides that neither the Seadrill Member nor our officers or directors will be liable for monetary damages to us, our members or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Seadrill Member, our directors or officers or those other persons engaged in actual fraud or willful misconduct.

The standard of care applicable to an officer or director of Seadrill when that individual is acting in such capacity is, in a number of circumstances, stricter than the standard of care the same individual may have when acting as our officer or director. The fact that our officers or directors may have a fiduciary duty to Seadrill does not, however, diminish the duty that such individual owes to us. Compliance by such officer or director with such individual's duty to us should not result in a violation of such individual's duties to Seadrill.

In order to become a member of us, a common unitholder is required to agree to be bound by the provisions in the operating agreement, including the provisions discussed above.

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Seadrill's ownership interest in us could decrease, and substantial future sales of our common units, could lead to a reduction in the trading price of our common units.

The Seadrill Member may transfer its Seadrill Member interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. In addition, our operating agreement does not restrict the ability of the members of the Seadrill Member from transferring their respective limited liability company interests in the Seadrill Member to a third party.

We have granted registration rights to Seadrill and certain of its affiliates. These unitholders have the right, subject to some conditions, to require us to file registration statements covering any of our common, subordinated or other equity securities owned by them or to include those securities in registration statements that we may file. As of March 31, 2021, Seadrill owned 2,627,575 common units and 1,654,335 subordinated units and all of the incentive distribution rights (through its ownership of the Seadrill Member). Following their registration and sale under an applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of our common units to decline.

If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940 which could force us to restructure and restrict our future activities.

If we cease to manage and control OPCO and are deemed to be an investment company under the Investment Company Act of 1940 because of our ownership of OPCO interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional independent directors.

The Seadrill Member, as the initial holder of all of the incentive distribution rights, may elect to cause us to issue additional common units to it in connection with a resetting of the target distribution levels related to the Seadrill Member's incentive distribution rights without the approval of the conflicts committee of the Board or holders of our common units and subordinated units. This may result in lower distributions to holders of the common units in certain situations.

The Seadrill Member, as the initial holder of all of the incentive distribution rights, has the right, at a time when there are no subordinated units outstanding and the Seadrill Member has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by the Seadrill Member, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, the Seadrill Member will be entitled to receive a number of common units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to the Seadrill Member on the incentive distribution rights in the prior two quarters. We anticipate that the Seadrill Member would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that the Seadrill Member could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued the common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause the common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued additional common units to the Seadrill Member in connection with resetting the target distribution levels related to the Seadrill Member's incentive distribution rights.

We may issue additional equity securities, including securities senior to the common units, without the approval of our unitholders, which could dilute the ownership interests of our existing unitholders.

We may, without the approval of our unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. Our issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

•our unitholders' proportionate ownership interest will decrease;

•the amount of cash available for distribution on each unit may decrease;

•because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•the relative voting strength of each previously outstanding unit may be diminished; and

•the market price of the common units may decline.

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Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $3.8750 per unit, plus any unpaid minimum quarterly distributions on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash. For a description of the subordination period, refer to Item 8 - Financial Information - Consolidated Statements and Other Financial Information - The Company's Cash Distribution Policy.

The Seadrill Member has a limited call right that may require our common unitholders to sell their common units at an undesirable time or price.

If at any time the Seadrill Member and its affiliates own more than 80% of the common units, the Seadrill Member will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price of our common units. The Seadrill Member is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right. As a result, the holders of our common units may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such common unitholders may also incur a tax liability upon a sale of their common units.

Unitholders may have liability to repay distributions.

Under some circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the Marshall Islands Act, we may not make a distribution to our unitholders if at the time of the distribution, after giving effect to the distribution, all our liabilities, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to our specified property, exceed the fair value of our assets, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in our assets only to the extent that the fair value of that property exceeds that liability. The Marshall Islands Act provides that for a period of three years from the date of the impermissible distribution (or longer if an action to recover the distribution is commenced during such period), members who received the distribution and who knew at the time of the distribution that it violated the Marshall Islands Act will be liable to the limited liability company for the distribution amount. Assignees who become substituted members are liable for the obligations of the assignor to make contributions to us that are known to the assignee at the time it became members and for unknown obligations if the liabilities could be determined from the operating agreement.

Because we are a foreign limited liability company, you may not have the same rights that a unitholder in a U.S. limited liability company may have.

We are organized under the laws of Marshall Islands, and substantially all of our assets are located outside of the United States. In addition, our directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to bring an action against us or against these individuals in the United States if you believe that your rights have been infringed under securities laws or otherwise. Even if you are successful in bringing an action of this kind, the laws of Marshall Islands and of other jurisdictions may prevent or restrict you from enforcing a judgment against our assets or the assets of our directors or officers.

The provisions of the Marshall Islands Act resemble provisions of the limited liability company laws of a number of states in the United States, most notably Delaware. The Marshall Islands Act also provides that for non-resident limited liability companies it is to be applied and construed to make the laws of the Marshall Islands, with respect to the subject matter of the Marshall Islands Act, uniform with the laws of the State of Delaware and, so long as it does not conflict with the Marshall Islands Act or decisions of the High or Supreme Courts of the Marshall Islands the non-statutory law (or case law) of the State of Delaware is adopted as the law of the Marshall Islands. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited liability company statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of our unitholders and the duties of the Seadrill Member and our directors and officers under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. As a result, unitholders may have more difficulty in protecting their interests in the face of actions by the Seadrill Member and our officers and directors than would unitholders of a similarly organized limited liability company in the United States.

U.S. tax authorities may treat us as a "passive foreign investment company" for U.S. federal income tax purposes, which may have adverse tax consequences for U.S. unitholders.

A foreign corporation will be treated as a "passive foreign investment company" ("PFIC"), for U.S. federal income tax purposes if for any taxable year either (1) at least 75% of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50% 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, gains from the sale or exchange of investment property, and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute "passive income". U.S. unitholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their units in the PFIC.

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Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we believe that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the U.S. Internal Revenue Service (the "IRS"), on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.

If the IRS were to find that we are or have been a PFIC for any taxable year (and regardless of whether we remain a PFIC for any subsequent taxable year), our U.S. unitholders may face adverse U.S. federal income tax consequences. Under the PFIC rules, unless those unitholders make an election available under the U.S. Internal Revenue Code of 1986, as amended (the "Code") (which election could itself have adverse consequences for such unitholders, as discussed below under Item 10 - "Additional Information - E. Taxation"), such unitholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of the common units, as if the excess distribution or gain had been recognized ratably over the unitholder's holding period of the common units. In the event that our unitholders face adverse U.S. federal income tax consequences as a result of investing in common units, this could adversely affect our ability to raise additional capital through the equity markets. See Item 10 - "Additional Information - E. Taxation" for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. unitholders if we are treated as a PFIC.

Investors are encouraged to consult their own tax advisers concerning the overall tax consequences of the ownership of the common units arising in an investor's particular situation under U.S. federal, state, local or foreign law.

General Risk Factors

Interest rate fluctuations could affect our earnings and cash flow.

In order to finance our growth, we have incurred significant amounts of debt. The majority of our debt arrangements have floating interest rates. As such, significant movements in interest rates could have an adverse effect on our earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we use interest rate swaps to effectively fix a part of our floating rate debt obligations. The principal amount covered by interest rate swaps is evaluated continuously and determined based on our debt level, our expectations regarding future interest rates and our overall financial risk exposure. Although we enter into various interest rate swap transactions to manage exposure to movements in interest rates, there can be no assurance that we will be able to continue to do so at a reasonable cost or at all.

If we are unable to effectively manage our interest rate exposure through interest rate swaps in the future, any increase in market interest rates would increase our interest rate exposure and debt service obligations, which would exacerbate the risks associated with our leveraged capital structure.

Fluctuations in exchange rates and the non-convertibility of currencies could result in losses to us.

As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than United States Dollars ("U.S. Dollars" or "US$"). Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available in the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.

We use the U.S. Dollar as our functional currency because the majority of our revenues and expenses are denominated in U.S. Dollars. Accordingly, our reporting currency is also U.S. Dollars. We do, however, earn revenues and incur expenses in other currencies, and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.

Brexit, or similar events in other jurisdictions, could impact global markets, which may have an adverse impact on our business and operations as a result of changes in currency, exchange rates, tariffs, treaties and other regulatory matters.

A change in tax laws in any country in which we operate could result in higher tax expense.

We conduct our operations through various subsidiaries in countries throughout the world. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between the countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, which is beyond our control, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.

In addition, the United States in December 2017 enacted major tax reform legislation. This is likely to continue to have a material impact on the amount of overall U.S. tax expense of the Group due to reduced effective tax deductions for certain payments our U.S. operating companies make to non-U.S. rig owners and other Group and affiliated companies.

The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate the repayment of funds that we have borrowed.

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Our debt agreements impose operating and financial restrictions on us. These restrictions may prohibit, or otherwise limit, our ability to undertake certain business activities without consent of the lending banks. These restrictions include:

• executing other financing arrangements;

• incurring additional indebtedness;

• creating or permitting liens on our assets;

• selling our drilling units or the shares of our subsidiaries;

• making investments;

• changing the general nature of our business;

• paying distributions to our unitholders;

• changing the management and/or ownership of the drilling units; and

• making capital expenditures.

Our lenders' interests may be different from ours and we may not be able to obtain our lenders' consent for requests that may be beneficial to our business. This may impact our performance.

In addition, several of our debt agreements require us to maintain certain specified financial ratios and to satisfy covenants, including ratios and covenants that pertain to, among other things, our liquidity and a net leverage ratio under our secured rig financing credit facilities.

In the future, to the extent our operating results indicate that we may not meet the net leverage ratio of our secured credit facilities, or a liquidity requirement, there are a number of actions available which are under management's control. We cannot provide any assurances that management's actions will resolve compliance with the leverage ratio, liquidity requirement or any other financial covenant. In the event that we fail to comply with the covenants in our credit facilities, we would be considered in default, after any applicable notice from our lenders, which would enable applicable lenders to accelerate the repayment of amounts outstanding and exercise remedies, subject to applicable cure or grace periods, and we would need to seek an amendment or waiver from the applicable lender groups.

Such amendments or waivers from our lenders may be subject to competing interests of the lending institutions. We cannot provide any assurances that we will be able to obtain such an amendment or waiver. If we are not able to obtain waivers or amendments, or if such waivers or amendments have onerous conditions attached, this may limit our ability to make decisions in the best interests of our business.

If we are unable to comply with any of the restrictions and covenants in our current or future debt financing agreements, and we are unable to obtain a waiver or amendment from our lenders for such noncompliance, a default could occur under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable. Our drilling units and equity interests in our subsidiaries serve as security for our secured indebtedness. If our lenders were to foreclose their liens on our drilling units or the equity interests in our subsidiaries in the event of a default, this would impair our ability to continue our operations.

Uncertainty regarding the London Interbank Offered Rate ("LIBOR") may adversely impact our indebtedness under our credit and loan facilities, which could have a material adverse effect on our business, financial condition and results of operations.

In July 2017, the U.K. Financial Conduct Authority announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Proposed alternative reference interest rates so far are based on overnight tenors only, while the most frequently used LIBOR rates are for one, three and six month tenors. Most of our credit and loan facilities are linked to LIBOR. When LIBOR ceases to exist, we may need to amend our credit and loan facilities based on a new standard that is established, if any. The basis of calculation of such standard is not yet agreed upon amongst market participants and as a result the cost of our borrowings may increase. In addition, any resulting differences in interest rate standards among our assets and our financing arrangements may result in interest rate mismatches between our assets and the borrowings used to fund such assets. There is no guarantee that a transition from LIBOR to an alternative reference interest rate will not result in financial market disruptions or significant increases in benchmark rates, or borrowing costs to borrowers, any of which could have an adverse effect on our business, financial condition and results of operations.

A loss of a major tax dispute or a successful tax challenge to our tax positions, including our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in higher taxes on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

Our tax returns are subject to review and examination. We do not recognize the benefit of income tax positions that we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any of our tax positions, including our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries; or if the terms of certain Double Taxation Treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our taxes on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected. For additional information on tax assessments and claims issued, refer to Note 7 – "Taxation" to the Consolidated Financial Statements included herein.

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A change in laws and regulations in any country in which we operate could have a negative impact on our business

During 2017, the European Union Economic and Financial Affairs Council released a list of non-cooperative jurisdictions for tax purposes. The stated aim of the list, and accompanying report, was to promote good governance worldwide in order to maximize efforts to prevent tax fraud and tax evasion. Bermuda was not on the list of non-cooperative jurisdictions, but did feature in the report as having committed to address concerns relating to economic substance by December 31, 2018. In accordance with that commitment, Bermuda enacted the Economic Substance Act 2018 (the "ESA") in December 2018. The ESA requires each registered entity to maintain a substantial economic presence in Bermuda and provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (i) it is directed and managed in Bermuda, (ii) its core income-generating activities (as may be further prescribed) are undertaken in Bermuda with respect to the relevant activity, (iii) it maintains adequate physical presence in Bermuda, (iv) it has adequate full time employees in Bermuda with suitable qualifications and (v) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity. A registered entity that carries on a relevant activity is obliged under the ESA to file a declaration with the Bermuda Registrar of Companies on an annual basis containing certain information. At present, the impact of the ESA is still unclear and it is difficult to predict the nature and effect of these requirements on the Bermuda incorporated subsidiaries of the Company. We have undertaken an evaluation and continue to monitor the potential effect ESA will have on the Company's Bermuda subsidiaries. Similar legislation has been enacted in Cayman Islands and we have adopted the same approach as in the case of Bermuda.

We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.

We are currently involved in various litigation and arbitration matters, and we anticipate that we will be involved in dispute matters from time to time in the future. The operating and other hazards inherent in our business expose us to disputes, including personal injury disputes, environmental and climate change litigation, contractual disputes with customers, intellectual property and patent disputes, tax or securities disputes, regulatory investigations and maritime lawsuits, including the possible arrest of our drilling units. We cannot predict, with certainty, the outcome or effect of any claim or other dispute matters, or a combination of these. If we are involved in any future disputes, or if our positions concerning current disputes are found to be incorrect, there may be an adverse effect on our business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits and the diversion of management's attention to these matters.

We may also be subject to significant legal costs in defending these actions, which we may or may not be able to recoup depending on the results of such claim. For additional information on litigation matters that we are currently involved in, please see "Item 8 - "Financial Information - Consolidated Statements and Other Financial Information - Legal Proceedings."

If we fail to comply with requirements relating to internal control over financial reporting our business could be harmed and our common unit price could decline.

Rules adopted by the Securities and Exchange Commission pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 require that we assess our internal control over financial reporting annually. The rules governing the standards that must be met for management to assess its internal control over financial reporting are complex. They require significant documentation, testing, and possible remediation of any significant deficiencies in and/or material weaknesses of internal controls in order to meet the detailed standards under these rules. Although we have evaluated our internal control over financial reporting as effective as of December 31, 2020, in future fiscal years, we may encounter unanticipated delays or problems in assessing our internal control over financial reporting as effective or in completing our assessments by the required dates. In addition, we cannot assure you that our independent registered public accountants will attest that internal control over financial reporting is effective in future fiscal years.

If we are unable to maintain effective internal controls over financial reporting and disclosure controls, investors may lose confidence in our reported financial information, which could lead to a decline in the price of common units, limit our ability to access the capital markets in the future and require us to incur additional costs to improve our internal control over financial reporting and disclosure control systems and procedures. Further, if lenders lose confidence in the reliability of our financial statements, it could have a material adverse effect on our ability to fund our operations.

Data protection and regulations related to privacy, data protection and information security could increase our costs and our failure to comply could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations, as well as have an impact on our reputation.

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We are subject to regulations related to privacy, data protection and information security in the jurisdictions in which we do business. As privacy, data protection and information security laws are interpreted and applied, compliance costs may increase, particularly in the context of ensuring that adequate data protection and data transfer mechanisms are in place.

In recent years, there has been increasing regulatory enforcement and litigation activity in the areas of privacy, data protection and information security in the U.S. and in various countries in which we operate. In addition, legislators and/or regulators in the U.S., the European Union and other jurisdictions in which we operate are increasingly adopting or revising privacy, data protection and information security laws that could create compliance uncertainty and could increase our costs or require us to change our business practices in a manner adverse to our business. For example, the European Union and U.S. Privacy Shield framework was designed to allow for legal certainty regarding transfers of data. However, the agreement itself faces a number of legal challenges and is subject to annual review. This has resulted in some uncertainty and compliance obligations with regards to cross-border data transfers. Moreover, compliance with current or future privacy, data protection and information security laws could significantly impact our current and planned privacy, data protection and information security related practices, our collection, use, sharing, retention and safeguarding of consumer and/or employee information and some of our current or planned business activities. Our failure to comply with privacy, data protection and information security laws could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations and overall business, as well as have an impact on our reputation. For example, the General Data Protection Regulations of the European Union is enforceable in all 28 EU member states as of May 25, 2018 and will require us to undertake enhanced data protection safeguards, with fines for non-compliance up to 4% of global total annual worldwide turnover or €20 million (whichever is higher), depending on the type and severity of the breach.

Item 4.         Information on the Company

    A.     History and Development of the Company

Company Details

Seadrill Partners LLC was formed under the Laws of the Republic of Marshall Islands on June 28, 2012 with registration number 962166. Seadrill Partners LLC is the parent company of the group of companies collectively known as Seadrill Partners.

Seadrill Partners LLC is a limited liability company. Its principal executive headquarters are maintained at 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom and its telephone number at that address is +44 20 8811 4700. Its agent for service of process in the United States is Watson Farley & Williams LLP and its address is 250 West 55th Street New York, New York 10019.

Our website address is www.seadrillpartners.com. Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 20-F 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 20-F, quarterly and semi-annual reports on Form 6-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.

Significant developments for the period from January 1, 2019 through December 31, 2020

In this section we have set out important events in the development of our business. This includes information concerning the nature and results of any material reclassification, merger or consolidation of the company or any of its significant subsidiaries; acquisitions or dispositions of material assets other than in the ordinary course of business; any material changes in the mode of conducting the business; material changes in the types of products produced or services rendered; name changes; or the nature and results of any bankruptcy, receivership or similar proceedings with respect to the company or significant subsidiaries. This section covers the period from January 1, 2019 through December 31, 2020.

Restructuring Agreement and bankruptcy proceedings under Chapter 11

Since 2019 we have been engaged in extensive discussions with our lenders to refinance or extend the debt obligation under our credit facilities that falls due in 2021. However, we were unable to refinance or extend the obligation on terms that were as favorable as the terms of our existing facilities. On December 1, 2020, in consultation and with the support of an ad hoc group of lenders under the Company’s Term Loan B credit facility the Company and certain of our direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petitions under chapter 11 of the Bankruptcy Code to preserve value and to continue the operation and marketing its assets. The voluntary petitions for reorganization under Chapter 11 has triggered a stay on enforcement of remedies with respect to our debt obligations.

The Company intends to use the bankruptcy process to ensure that all customer and employee obligations are met without interruption and to complete a consensual restructuring of its debt. The objectives of the restructuring are to build a bridge to a recovery and achieve a sustainable capital structure.

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On December 4, 2020, the Southern District of Texas Bankruptcy Court overseeing the Company's chapter 11 restructuring proceedings granted the relief requested in the Company’s first-day motions related to ordinary course business activities. The approved motions give the Company the authority to, among other things, continue to pay employee wages and benefits without interruption, continue to utilize its cash management system and continue to pay critical third-party suppliers and vendors.

Term Loan B super senior loans

We entered into agreements with Term Loan B ("TLB") lenders in July and October 2020 respectively, whereby the TLB interest that was due on June 30, 2020 and September 30, 2020 was converted into super senior loans. As a result, $63.7 million and $63.3 million super senior loans, maturing in February 2021 were created carrying PIK interest of LIBOR plus 1000 basis points and a 10% exit premium. As part of this agreement, the West Vela, West Polaris, T-15 and T-16 have been pledged as collateral for the TLB.

Management agreements

On February 3, 2021 the Company entered into a management agreement with Energy Drilling to maintain, market and operate the Seadrill Partners owned tender rigs T-15, T-16 and West Vencedor. The agreement started a 90-day transition period of services provided from Seadrill Limited to Energy Drilling.

On February 10, 2021 we submitted a motion to the Bankruptcy Court for the approval of a new management services agreement with Vantage Drilling for certain rigs in the Seadrill Partners Fleet. Following the execution of the Vantage Drilling management services agreement, the Debtors continued to receive proposals with respect to the operation of their floater vessels. Because the Vantage Drilling management services agreement remained subject to Bankruptcy Court approval (and was therefore not binding upon the Debtors), the Debtors undertook to assess such alternative proposals. Upon assessing such alternative proposals, the Debtors determined that the commercial proposition served by using a combination of Vantage Drilling, Diamond Offshore Drilling Inc. (“Diamond”), and Odfjell Drilling Ltd. (“Odjfell”), each as managers of certain of the Debtors’ floater vessels, was superior to the original Vantage Drilling management structure. Therefore, on March 16, 2021, the Debtors filed a supplement to the motion seeking approval of management services agreements with Vantage Drilling, Diamond, and Odjfell. On March 18, 2021, the Bankruptcy Court approved the motion, authorizing the Debtors to enter into management services agreements with Diamond, Odfjell, and an amended management services agreement with Vantage Drilling.

Seadrill restructuring

On February 7, 2021 and February 10, 2021, Seadrill Limited and most of its subsidiaries (the "Seadrill Limited Debtors"), our largest unit holder and key service provider, filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, triggering a stay on enforcement of remedies with respect to its debt obligations. The Seadrill Limited Debtors were granted “first-day” relief which will enable the Company to continue operations without interruption.

Drilling contracts

The below table shows the status of our drilling contracts at March 31, 2021:

Rig	Built	Status at March 31, 2021	Customer	Contracted until
Semi-submersible
West Sirius	2008	Available	-	-
West Aquarius	2009	Available	-	-
West Capricorn	2011	Available	-	-
West Leo	2012	Available	-	-
Drillship
West Capella	2008	Contracted	Petronas	Jun 2021
West Polaris	2008	Available	-	-
West Auriga	2013	Available	-	-
West Vela	2013	Contracted	BP	May 2021
Tender Rig
West Vencedor	2009	Available	-	-
T-15	2013	Available	-	-
T-16	2013	Available	-	-

Capital Expenditures

Capital expenditures were approximately $28.7 million, $111.1 million and $115 million in the years ended 2020, 2019 and 2018 respectively. Our capital expenditures relate primarily to additional equipment for our existing drilling units and maintenance. We financed these capital expenditures through cash generated from operations and secured and unsecured debt arrangements.

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NYSE Matters

The NYSE filed a Form 25 with the SEC in connection with the delisting and deregistration of our common units on December 11, 2019. Delisting of our common units from the NYSE became effective 10 days after the filing date of the Form 25. The Form 25 was filed as part of delisting procedures resulting from the company's low market capitalization, as we previously announced on September 6, 2019. Our common units currently trade on the over-the-counter market ("OTC") under the ticker symbol "SDLPQ". In connection with the NYSE delisting, we obtained amendments to the West Vela facility and the West Polaris facility that would no longer require the common units to be listed on the NYSE.

Quarterly Distributions to Common Unitholders

In January 2020, we announced that we would eliminate the quarterly distribution to our common unitholders. The move was made to preserve liquidity ahead of debt maturities in the second half of 2020 and first quarter of 2021.

    B.     Business Overview

Introduction

We are an offshore drilling contractor providing offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships, semi-submersible rigs and tender rigs for operations in shallow to ultra-deepwater areas in both benign and harsh environments.

We contract our drilling units primarily on a dayrate basis to drill wells for our customers, typically oil super-majors and independent oil and gas companies. We are recognized for providing high quality operations, in some of the most challenging sectors of offshore drilling.

Our Fleet

We believe our fleet is comparatively one of the youngest and modern of all the major offshore drilling contractors with an average fleet age of approximately 9.7 years. We currently own and operate a fleet of 11 drilling units, including four drillships, four semi-submersible rigs and three tender rigs. You may find additional information on our drilling units in Item 4 - "Information on the Company - D. Property, Plant and Equipment".

Drillships

Drillships are self-propelled ships equipped for drilling offshore in water depths ranging from 1,000 to 12,000 feet, and are positioned over the well through a computer-controlled thruster system. Drillships are suitable for drilling in remote locations because of their mobility and large load-carrying capacity. Depending on country of operation, drillships operate with crews of 50 or more people.

Semi-submersible drilling rigs

Semi-submersibles are self-propelled drilling rigs consisting of an upper working and living quarters deck connected to a lower hull consisting of columns and pontoons. Such rigs operate in a "semi-submerged" floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The rig is situated over a wellhead location and remains stable for drilling in the semi-submerged floating position, due in part to its wave transparency characteristics at the water line.

Semi-submersible rigs can be either moored or dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors and typically operate in water depths ranging up to 1,500 feet. Dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system and typically operate in water depths ranging from 1,000 to 12,000 feet. Depending on country of operation, semi-submersible rigs generally operate with crews of 50 or more people.

Tender rigs

Tender rigs are self-erecting rigs which conduct production drilling from fixed or floating platforms. During drilling operations, the tender rig is moored next to the platform. The modularized drilling package, stored on the deck during transit, is lifted prior to commencement of operations onto the platform by the rig's integral crane. To support the operations, the tender rig contains living quarters, helicopter deck, storage for drilling supplies, power machinery for running the drilling equipment and well completion equipment. There are two types of self-erecting tender rigs, barge type and semi-submersible (semi-tender) type. Tender barges and semi-tenders are equipped with similar equipment but the semi-tenders' hull structure allows the unit to operate in rougher weather conditions. Tender rigs allow for drilling operations to be performed from platforms without the need for permanently installed drilling packages. Self-erecting tender rigs generally operate with crews of 50 or more people.

Rig management arrangements

During the year ended December 31, 2020, Seadrill Limited was responsible for the management, marketing and operation of our fleet of drilling units through a series of management, operational support and technical supervision service agreements. We were charged a fee for the services provided to us. Subsequent to year-end management service agreements have been agreed with other operators. Refer to Item 4 - "Information on the Company - A. History and Development of the Company".

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Our Competitive Strengths

We believe that our competitive strengths include:

Technologically advanced and young fleet

We believe our drilling units are among the most technologically advanced in the world. The majority of our rigs were built after 2008 and offer superior technical capabilities, operational flexibility and reliability. We believe, based on our modern fleet and strong operational track record, that we will be better placed to secure new drilling contracts than some of our competitors with older, less advanced rig fleets.

Commitment to safety and efficiency

We believe that the combination of quality drilling units and experienced and skilled employees allows us to provide our customers with safe and effective operations. Quality assets and operational expertise allow us to establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers.

Commitment to the environment

We believe we act responsibly towards the environment. We seek to minimize and mitigate the impacts of our businesses on the environment and ensure that contingency plan and emergency response procedures are always in place to mitigate the possible harm that could be caused in the event of an incident.

Business Strategy

Our immediate objectives during the current industry downturn include the following:

Protect our revenue and contract backlog by continuing to provide excellent service to our customers

We are a leading offshore deepwater drilling company and our mission is to continue to be a preferred offshore drilling contractor and to deliver excellent performance to our clients by consistently exceeding their expectations for performance and safety standards. We believe that we have one of the most modern fleets in the industry and believe that by combining quality assets and experienced and skilled employees we will be able to provide our customers with safe and effective operations, and maintain our position as a preferred provider of offshore drilling services for our customers. We believe that a combination of quality drilling rigs, highly skilled employees and strong operations will facilitate the procurement of term contracts at premium dayrates. By doing this we intend to maximize opportunities for new drilling contracts, while minimizing chances of contract terminations.

Establish a sustainable capital structure

Our current priority is to establish a sustainable capital structure amidst a challenging market backdrop that ensures safe and efficient operation of our drilling units and provides adequate liquidity and maturity runway that decreases refinancing requirements. We are currently involved in lender discussions to refinance or extend certain debt maturities.

Longer term, we have the following objectives:

• Pursue Long-term Contracts and Maintain Stable Cash Flows. We will continue to pursue long-term contracts to maintain stable and predictable operating cash flows. We believe that this focus will enable us to access equity and debt capital markets on attractive terms and, therefore, facilitate our growth strategy.

• Provide Excellent Customer Service and Continue to Prioritize Safety as a Key Element of The Company's Operations. We believe that Seadrill Partners LLC has developed a reputation as a preferred offshore drilling contractor and that we can capitalize on this reputation by continuing to provide excellent customer service. We seek to deliver exceptional performance for our customers by consistently meeting or exceeding their expectations for operational performance, including by maintaining high safety standards and minimizing downtime.

• Maintain a Modern and Reliable Fleet. We have comparatively one of the youngest and most technologically advanced fleets in the industry and have plans to maintain a modern and reliable fleet.

We can provide no assurance, however, that we will be able to implement our business objectives described above, particularly in the current challenging low oil price market environment.

Market Overview

We provide operations in oil and gas exploration and development in regions throughout the world and our customers have included major oil and gas companies, national oil companies and independent oil and gas companies.

Seasonality

In general, seasonal factors do not have a significant direct effect on our business. We have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operation of our rigs, but generally such operational interruptions do not have a significant impact on our revenues. Such adverse weather could include the hurricane season in the Gulf of Mexico and the monsoon season in Southeast Asia.

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Customers

Offshore exploration and production is a capital intensive, high-risk industry. Operating and pursuing opportunities in deepwater basins significantly increases the amount of capital required to effectively undertake such operations. A significant number of operators in this segment of the offshore exploration and production industry are either national oil companies, major oil and gas companies or well-capitalized large independent oil and gas companies.

For the year ended December 31, 2020, BP, Reliance and ExxonMobil accounted for 75.8%, 8.6% and 8.3% of our total revenues, respectively.

Competition

The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to small locally-owned companies.

The demand for offshore drilling services is driven by oil and gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and gas companies’ expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products, the availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for drilling services. Variations in market conditions during cycles impact us in different ways, depending primarily on the length of drilling contracts in different regions.

Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, technical specification, rig location, condition and integrity of equipment, their record of operating efficiency, safety performance record, crew experience, reputation and industry standing and customer relations.

Furthermore, competition for offshore drilling rigs is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate upgrades of the unit and its equipment to specific regional requirements.

In particular, for rigs to operate in harsh environments, such as offshore Canada, as opposed to benign environments, such as the Gulf of Mexico, West Africa, and Southeast Asia, more demanding weather conditions would require more costly investment in the outfitting and maintenance of the drilling units.

For further information on current market conditions and global offshore drilling fleet, please see "Market Overview" and Item 5 - "Operating and Financial Review and Prospects-Trend Information".

Principal Suppliers

We source the equipment used on our drilling units from well-established suppliers, including: Cameron International Corp. and National Oilwell Varco, Inc. ("NOV"), each of which supply blowout preventers, and, with respect to NOV, top drives (the device used to turn the drillstring, which is a combination of devices that turn the drill bit), drawworks (the hoisting mechanism on a drilling unit) and other significant drilling equipment; Kongsberg Gruppen, which supplies dynamic positioning systems; Aker-MH AS, which supplies drilling software as well as top drives and drawworks; Rolls-Royce, which supplies thrusters; and Caterpillar Inc., which supplies cranes.

In addition, our customers are responsible for providing the fuel to be used by a drilling unit when it is under contract to them, at their own cost. We are not dependent on any one supplier.

Risk of Loss and Insurance

Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling contractors are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our rig insurance package policy provides insurance coverage for physical damage to our rigs, loss of hire for our working rigs and third-party liability.

i. Physical Damage Insurance

We purchase hull and machinery insurance to cover for physical damage to our drilling rigs. We retain the risk, through self-insurance, for the deductibles relating to physical damage insurance on our drilling unit fleet; currently, a maximum of $5 million per occurrence.

ii. Loss of Hire Insurance

Seadrill purchases insurance to cover for loss of revenue for their operational rigs in the event of extensive downtime caused by physical damage to its drilling units and those of the Company (floaters and semi-tenders), where such damage is covered under Seadrill's physical damage insurance, and charges us for the cost related to our fleet.

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The loss of hire insurance has a deductible period of up to 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which we are compensated for loss of revenue are limited to 290 days per event and aggregated per year. The daily indemnity will vary from 75% to 100% of the contracted dayrate.

We retain the risk related to loss of hire during the initial 60 day period, as well as any loss of hire exceeding the number of days permitted under the insurance policy. If the repair period for any physical damage exceeds the number of days permitted under the loss of hire policy, we will be responsible for the loss of revenue in such period. We do not purchase loss of hire insurance on the T-15 and T-16.

iii. Protection and Indemnity Insurance

Seadrill purchases Protection and Indemnity insurance (P&I) and excess liability insurance for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling units to cover claims of up to $500 million per event and in the aggregate and up to $700 million per event and in the aggregate for the West Capricorn, West Auriga and West Vela.

In the event of no drilling activities, the excess liability insurance is suspended and therefore the limit is reduced from $500 million to $350 million per event and in the aggregate with the exception of the West Capricorn, West Auriga and West Vela which is reduced from $700 million to $500 million per event and in aggregate.

We retain the risk for the deductible of up to $0.5 million per occurrence relating to protection and indemnity insurance.

iv. Windstorm Insurance

We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico (West Sirius, West Capricorn, West Vela and West Auriga) with a Combined Single Limit of $100 million in the annual aggregate, which includes loss of hire.

Environmental and Other Regulations in the Offshore Drilling Industry

Our operations are subject to numerous laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permits requirements, local content requirements and other national, state and local laws and regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. See Item 3 - "Key Information - D. Risk Factors - Risks Relating to Our Company and Our Business - Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations".

i.Flag State Requirements

All our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. The flag state requirements are international maritime requirements and, in some cases, further interpolated by the flag state itself. These include engineering, safety and other requirements related to the maritime industry. In addition, each of our drilling units must be "classed" by a classification society. The classification society certifies that the drilling rig is "in-class," signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the flag state and the international conventions of which that country is a member. Maintenance of class certification requires expenditure of substantial sums and can require taking a drilling unit out of service from time to time for repairs or modifications to meet class requirements.  Our drilling units must generally undergo class surveys annually and a renewal survey once every five years. In addition, for some of the internationally-required class certifications, such as the Code for the Construction and Equipment of Mobile Offshore Drilling Units (the "MODU Code") certificate, the classification society will act on a flag state's behalf. The Classification Society can also act on behalf of the Flag State for survey and issue of International Certification. Port States can also impose stricter regimes than the Flag State when the drilling unit is operating in their territorial waters.

ii.International Maritime Regimes

Applicable international maritime regime requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships ("MARPOL"), the International Convention on Civil Liability for Oil Pollution Damage of 1969 (the "CLC"), the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974 ("SOLAS"), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, MODU Code, and the International Convention for the Control and Management of Ships' Ballast Water and Sediments in February 2004 (the "BWM Convention").  These various conventions regulate air emissions and other discharges to the environment from our drilling units worldwide, and we may incur costs to comply with these regimes and continue to comply with these regimes as they may be amended in the future. In addition, these conventions impose liability for certain discharges, including strict liability in some cases. See Item 3 - "Key Information - D. Risk Factors - Risks Relating to Our Company and Our Business - We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business".

The BWM Convention calls for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention entered into force on September 8, 2017. Under its requirements, only ballast water treatment will be accepted from the next International Oil Pollution Prevention renewal survey (after September 8, 2019). All Seadrill units considered in operational status are in full compliance with the staged implementation of the BWM Convention by International Maritime Organization guidelines.

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As of January 1, 2020, MARPOL Annex VI, Regulation 14, requires the sulphur content of any fuel used on board ships is limited to 0.5% m/m (percent by mass). The fuel we use is compliant to these regulations. Ships must either burn compliant fuel, or use an exhaust gas cleaning system, which have fitting and upkeep costs.

iii.Environmental Laws and Regulations

Applicable environmental laws and regulations include the U.S. Oil Pollution Act of 1990, ("OPA"), the Comprehensive Environmental Response, Compensation and Liability Act, ("CERCLA"), the U.S. Clean Water Act, ("CWA"), the U.S. Clean Air Act, ("CAA"), the U.S. Outer Continental Shelf Lands Act ("OCSLA"), the U.S. Maritime Transportation Security Act of 2002 ("MTSA"), European Union regulations, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations, and Brazil's National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. Implementation of new environmental laws or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition. See Item 3 - "Key Information - D. Risk Factors - Risks Relating to Our Company and Our Business - We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business".

iv.Safety Requirements

Our operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where we operate. The United States undertook substantial revision of safety regulations applicable to our industry following the 2010 Deepwater Horizon Incident, in which we were not involved. Other countries also have undertaken or are undertaking a review of their safety regulations related to our industry. These safety regulations may impact our operations and financial results by adding to the costs of exploring for, developing and producing oil and gas in offshore settings. For instance, in 2016, the BSEE published a final rule that sets more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas drilling and separately announced a risk-based inspection program for offshore facilities. Also, in 2016, BOEM issued a final Notice to Lessees and Operators imposing more stringent supplemental bonding procedures for the decommissioning of offshore wells, platforms and pipelines. These regulations, which may result in additional costs for us, have since become the subject of additional review and possible revision by BSEE and BOEM and, as a result, we cannot predict their impact on our future operations. The EU also has undertaken a significant revision of its safety requirements for offshore oil and gas activities through the issue of the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations. These other future safety and environmental laws and regulations regarding offshore oil and gas exploration and development may increase the cost of our operations, lead our customers to not pursue certain offshore opportunities and result in additional downtime for our drilling units. In addition, if material spill events similar to the Deepwater Horizon Incident were to occur in the future, or if other environmental or safety issues were to cause significant public concern, the United States or other countries could elect to, again, issue directives to cease drilling activities in certain geographic areas for lengthy periods of time.

v.Navigation and Operating Permit Requirements

Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.

vi.Local Content Requirements

Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in our operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in our local operating subsidiaries and drilling unit contracts. Although these requirements have not had a material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

vii.Other Laws and Regulations

In addition to the requirements described above, our international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of, and operation of, drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment. There is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.

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    C.     Organizational Structure

A simplified organizational structure as of December 31, 2020 is shown below.

*Seadrill Limited references both Seadrill Limited and wholly owned subsidiaries of Seadrill Limited.

Seadrill owns 34.9% of the common units of Seadrill Partners LLC and 100% of the subordinated units of Seadrill Partners LLC and owns and controls the Seadrill Member.

A full list of the Company's significant operating and rig-owning subsidiaries is included in Exhibit 8.1.

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    D.     Property, Plant and Equipment

Other than our fleet of drilling units, we do not have any material property. The following table provides additional information about our fleet as of December 31, 2020:

Rig	Seadrill Partners Ownership Interest (2)	Year Built	Water Depth (feet)	Drilling Depth (feet)
Semi-submersible
West Sirius	51%	2008	10,000	35,000
West Aquarius	58%	2009	10,000	32,800
West Capricorn	51%	2011	10,000	37,500
West Leo	58%	2012	10,000	35,000
Drillship
West Capella (1)	32%	2008	10,000	37,500
West Polaris	58%	2008	10,000	37,500
West Auriga	51%	2013	12,000	37,500
West Vela	51%	2013	12,000	37,500
Tender Rig
West Vencedor	58%	2010	6,500	30,000
T-15	100%	2013	6,500	20,000
T-16	100%	2013	6,500	30,000

(1) We own 58% of Seadrill Operating LP, which controls and owns 56% of the entity that owns the West Capella.

(2) Seadrill owns the remaining interest in each of our rigs.

Item 4A.     Unresolved Staff Comments

None.

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Item 5.         Operating and Financial Review and Prospects

Overview

In this section, we present management’s discussion and analysis of results of operations and financial condition. It should be read in conjunction with our Consolidated Financial Statements and accompanying notes thereto included herein. You should also carefully read the following sections of this annual report entitled "Cautionary Statement Regarding Forward-Looking Statements," Item 3 - "Key Information - A. Selected Financial Data", Item 3 - "Key Information— D. Risk Factors" and Item 4 - "Information on the Company." Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information.

The Company's Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and are presented in U.S. Dollars. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding going concern as described in Note 1 - "General information" to the Consolidated Financial Statements included herein.

Restructuring Agreement and bankruptcy proceedings under Chapter 11

Prior to the filing of the Chapter 11 proceeding we have been engaged in extensive discussions with our lenders to refinance or extend the debt obligation under our credit facilities that falls due in 2021. However, we were unable to refinance or extend the obligation on terms that were as favorable as the terms of our existing facilities.

On December 1, 2020, the Company and certain of our direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petitions under chapter 11 of the Bankruptcy Code to preserve value and to continue the operation and marketing its assets. The voluntary petition for reorganization under Chapter 11 has triggered a stay on enforcement of remedies with respect to our debt obligations. The Company intends to use the bankruptcy process to ensure that all customer and employee obligations are met without interruption and to complete a consensual restructuring of its debt. The objectives of the restructuring are to build a bridge to a recovery and achieve a sustainable capital structure. We have proposed to achieve this by extending debt maturities, reducing fixed amortization, amending financial covenants and raising new capital.

As described in Item 3D, upon the filing of voluntary petitions to restructure under the protections Chapter 11 of the Bankruptcy Code, we operate the business as debtors-in-possession under supervision of the Bankruptcy Court. Debtors-in-possession status requires that we obtain approval of the Bankruptcy Court with respect to our business. Accordingly, ultimate discretion of many operational and non-routine activities is subject to final supervision of the Bankruptcy Court and does not reside in solely with management.

For periods subsequent to filing for bankruptcy, we have prepared our consolidated financial statement in accordance with Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Pre-petition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. Please see Note 1 "General information - Basis of Preparation" and Note 4 "Chapter 11 Proceedings" to the Consolidated Financial Statements included herein for further information.

Contract Backlog

Our contract backlog as of December 31, 2020 totals $46.8 million and relates to our drillships.

Contract Backlog includes all firm contracts at the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period. Contract Backlog excludes revenues for mobilization, demobilization and contract preparation or other incentive provisions. Our contract backlog includes only firm commitments represented by signed drilling contracts. The full contractual operating dayrate may differ to the actual dayrate we ultimately receive. For example, 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 differ to the actual dayrate we ultimately receive because of several other 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.

The disruptive impacts of the oil price decline and COVID-19 could have an adverse effect on our ability to realize our backlog. Our customers may seek to terminate or renegotiate our contracts, which could result in lower dayrates or less favorable economic terms.

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 are available to our customers under certain circumstances.

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Factors Affecting our Results of Operations

We believe the principal factors that will affect our future results of operations include the following:

•Our ability to maintain liquidity for our business operations during the Chapter 11 proceedings.

•Our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing and the related increased performance and credit risks associated with our constrained liquidity position and capital structure.

•The COVID-19 global pandemic, the related public health measures implemented by governments worldwide and the impact on oil demand and prices.

•Our ability to successfully employ our drilling units at economically attractive dayrates as contracts expire or are otherwise terminated.

•Our ability to maintain good relationships with our existing customers and to increase the number of customer relationships.

•The number and availability of drilling units in our fleet.

•Changes in Seadrill Partners LLC's ownership of OPCO.

•Fluctuations in the price of oil and gas, which influence the demand for offshore drilling services.

•The effective and efficient technical management of our drilling units.

•Our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards.

•Economic, regulatory, political and governmental conditions that affect the offshore drilling industry.

•Accidents, natural disasters, adverse weather, equipment failure or other events outside of our control that may result in downtime.

•The financial condition of Seadrill and its ability to provide services to the Company under certain management, administrative and technical support agreements;

•Our ability to comply with financing agreements and the effect of the restrictive covenants in such agreements.

•Changes in the fair value of our interest rate swaps.

•Foreign currency exchange gains and losses.

•Our access to capital required to implement our business strategy.

•Increases in crewing and insurance costs and other operating costs.

•The level of debt and interest expense and amortization of deferred loan fees.

•The level of any distribution on Seadrill Partners LLC's common units.

Please read Item 3 - "Key Information—D. Risk Factors" for a discussion of certain risks inherent in the Company's business.

Important Financial and Operational Terms and Concepts

We use a variety of financial and operational terms and concepts when analyzing our performance. These include the following:

Contract Revenues

We contract our drilling units to oil and gas companies to provide offshore drilling services at an agreed dayrate for a specified contract term. Dayrates can vary, depending on the type of drilling unit and its capabilities, contract length, geographical location, operating expenses, taxes and other factors such as prevailing economic conditions. We do not provide "turnkey" or other risk-based drilling services to the customer. Instead, we provide a drilling unit and rig crews and charge the customer a fixed amount per day regardless of the number of days needed to drill the well. The customer bears substantially all the ancillary costs of constructing the well and supporting drilling operations, as well as most of the economic risk relative to the success of the well.

Where operations are interrupted or restricted due to equipment breakdown or operational failures, we may not receive dayrate compensation for the period of the interruption in excess of contractual allowances. Furthermore, the dayrate we receive may be reduced in instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or requested suspension of services by the customer and other operating factors.

However, contracts normally allow for compensation when factors beyond our control, including weather conditions, influence the drilling operations. In some cases contracts allow for compensation when planned maintenance activities are performed. In some contracts there are dayrate escalation clauses to compensate for industry specific cost increases as reflected in publicly available cost indexes.

We may receive lump sum or dayrate based fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to the start of drilling services. In some cases, we may also receive lump sum or dayrate based fees for demobilization upon completion of a drilling contract. We recognize revenue for mobilization, capital upgrades and non-contingent demobilization fees on a straight-line basis over the expected contract term.

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Our contracts may be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period because of a breakdown of major rig equipment, "force majeure" or upon the occurrence of other specified conditions. Some contracts include provisions that allow the customer to terminate the contract without cause for a specified early termination fee.

A drilling unit may be "stacked" if it has no contract in place. Drilling units may be either warm stacked or cold stacked. When a rig is warm stacked, the rig is idle but can deploy quickly if an operator requires its services. Cold stacking a rig involves reducing the crew to either zero or just a few key individuals and storing the rig in a harbor, shipyard or designated area offshore.

In certain countries, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We record tax-assessed revenue transactions on a net basis in the Consolidated Statement of Income.

Other Revenues

Other revenues include amounts recognized as early termination fees under the drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized at the point our performance obligations under the drilling contract have been satisfied and when any material contingencies or uncertainties are resolved. Other revenues also previously included operation support fees charged to Seadrill for certain onshore support services provided.

Economic Utilization

Economic utilization is calculated as the total revenue, excluding bonuses, received divided by the full operating dayrate multiplied by the number of days on contract in the period.

If a drilling unit earns its full operating dayrate throughout a reporting period its economic utilization would be 100%. However, there are many situations that give rise to a dayrate being earned that is less than the contractual operating rate. In such instances economic utilization reduces below 100%.

Examples of situations where the drilling unit would operate at reduced operating dayrates, include, among others, a standby rate, where the rig is prevented from commencing operations for reasons such as bad weather, waiting for customer orders, waiting on other contractors; a moving rate, where the drilling unit is in transit between locations; a reduced performance rate in the event of major equipment failure; or a force majeure rate in the event of a force majeure that causes the suspension of operations. In addition, the drilling unit could operate at a zero rate in the event of a shutdown of operations for repairs where the general repair allowance has been exhausted or for any period of force majeure in excess of a specific number of days allowed under a drilling contract.

Reimbursable Revenues and Expenses

Reimbursable revenues are revenues that constitute reimbursements from our customers for reimbursable expenses. Reimbursable expenses are expenses we incur on behalf, and at the request, of customers, and include provision of supplies, personnel and other services that are not covered under the drilling contract.

Operating Expenses

Operating expenses consist primarily of vessel and rig operating expenses, amortization of favorable contracts, reimbursable expenses, depreciation and amortization and selling, general and administrative expenses.

•Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked. This includes the personnel costs of offshore crews, running costs of the rigs, expenditures for repairs and maintenance activities, costs for onshore personnel that provide operational support to the rigs and management charges from Seadrill.

•Amortization of favorable contracts is amortization expense for acquired drilling contracts with above market rates. Where we acquire an in-progress drilling contract at above market rates through a business combination we record an intangible asset equal to its fair value on the date of acquisition. The asset is then amortized on a straight-line basis over its estimated remaining contract term.

•Selling, general and administrative expenses include management charges from Seadrill, legal and professional fees and other general administration expenses.

•Depreciation expense is based on the historical cost of our drilling units. Drilling units are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our rigs, when new, is 30 years. Costs related to periodic surveys and other major maintenance projects are capitalized as part of drilling units and amortized over the anticipated period covered by the survey or maintenance project, which is up to five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys and other major maintenance projects are included in depreciation expense.

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Other Operating Items

Other operating items include impairments of long-lived assets, impairments of goodwill, revaluation of contingent consideration and gains or losses on sale of assets.

•Impairments of long-lived assets arise where the carrying values of each of our drilling units are determined to not be recoverable and its fair value decreases below its carrying value.

•Impairments of goodwill arise where the fair value of a reporting unit that has goodwill recognized against it decreases below its carrying value.

•Revaluation of contingent consideration occurs where there are changes in the estimated fair value of deferred consideration liabilities. These estimates may increase or decrease as new market information becomes available.

•Gains or losses on sale of assets occur where proceeds received from an asset sale are higher or lower than the carrying value of the asset.

Financial Items

Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments and foreign exchange gain/loss.

•Interest income relates to the interest on cash deposits and amortization of mobilization revenue.

•Interest expense depends on the overall level of debt, and may significantly increase if we incur additional debt. Interest expense may also change with prevailing interest rates, although interest rate swaps or other derivative instruments may reduce the effect of these changes. As a result of filing for Chapter 11, no interest has been recognized from December 1, 2020. For further details refer to Note 4 - "Chapter 11 Proceedings" to the Consolidated Financial Statements included herein for further information.

•Gains and losses recognized on derivative financial instruments reflect various mark-to-market and counter party credit risk adjustments to the value of our interest rate swap agreements and the net settlement amount paid or received on swap agreements.

•Foreign exchange gains/loss recognized generally relate to transactions and revaluation of balances carried in currencies other than the U.S. Dollars.

•Reorganization items includes income and expenses directly associated with reorganization proceedings and include; advisory and professional fees directly associated with the Chapter 11 proceedings, unamortized debt issuance costs written off and interest income on surplus cash.

•Other financial expenses include the reversal of credit risk on derivatives and advisory and professional fees directly associated with the Chapter 11 proceedings incurred prior to filing.

Income Taxes

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities related to our ownership and operation of drilling units and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of taxes is based on net income or deemed income, the latter generally being a function of gross revenue.

Cost Inflation

The majority of our contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of cost inflation on revenues from long-term contracts, most of our long term contracts include escalation provisions. These provisions adjust the contractual dayrates each year based on stipulated cost increases, including wages, insurance and maintenance cost.

Critical Accounting Estimates

The preparation of the Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable.

Critical accounting estimates are important to the portrayal of both the Company's financial condition and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain. Basis of preparation and significant accounting policies are discussed in Note 1 - "General information", and Note 2 - "Accounting policies" to the Consolidated Financial Statements included herein.

We believe that the following are the critical accounting estimates used in the preparation of the Consolidated Financial Statements. In addition, there are other items within the Consolidated Financial Statements that require estimation.

Impairment of Drilling Units

The carrying values of our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. In 2020, the following events or changes in circumstances indicated that the carrying amount of the drilling units may not be recoverable:

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•The oil price collapse in the beginning of 2020, triggered by the combined impact of COVID-19 and demand shortfalls, has caused a significant delay in the recovery of the drilling industry. This has negatively impacted offshore rig utilization and market day rates as the supply of drilling units continue to exceed demand.

•The main industry players have not completed scrapping programs as expected. This has prevented a market consolidation and recovery as previously forecasted. The recovery of the benign environment floater market was slower and less pronounced than previously assumed, especially for semi-submersible units.

We estimated future undiscounted cash flows to judge the recoverability of carrying amounts of the rigs in Q1 2020 and Q4 2020. Cash flows used in recoverability assessments are prepared for each rig and based on the assumptions which are developed in the annual budgeting process and our five-year plan. These include assumptions about long-term day rates by rig, long-term economic utilization, contract probabilities, operating expenses, estimated maintenance and inspection costs, reactivation costs and timing for the cold stacked rigs, and recycling probability. The recycling assumption was based on our estimates of the internal rate of return following the reactivation, the length of time rigs being cold stacked and assumptions relating to the remaining useful life of the rigs.

Our assumptions about future dayrates and contract probabilities, which are also considered key assumptions, were based on independent market reports for the drilling industry. We assumed that day rates will remain constant after 2025. Reactivation timing of cold stacked rigs and recycling probabilities were also considered to be key assumptions and an area of significant management judgement. Assumptions about operating expenses, capital expenditure, stacking and reactivation costs, were based on contractual rates and historical information. Due to the inherent uncertainty around these assumptions, it is at least reasonably possible that a material change in impairment can occur in the near term.

An asset is impaired if its estimated undiscounted cash flows are less than the asset’s carrying values. On assessment of asset recoverability through an estimated undiscounted future net cash flows we calculated the value to be lower than the carrying value for 11 rigs. Impairment is measured by the amount by which the carrying value exceeds fair value. The discount rate is considered to be a key assumption in the discounted future net cash flows. We applied a weighted average cost of capital rate of 13.1% in December 2020 and 12.8% in March 2020 respectively. During 2020 we recorded an aggregate impairment loss of $4,210.4 million, resulting in a remaining net book value as at December 31, 2020 of $428.3 million for 9 rigs.

While maintaining all other assumptions, the following sensitivities have been performed:

–Increasing/decreasing the weighted average cost of capital by +/- 200 basis points would increase/decrease the impairment loss by $100.3 million and $134.6 million respectively.

–Increasing/decreasing the reactivation date of our cold stacked rigs by +/- one year would increase/decrease the impairment loss by $78.2 million and $25.0 million respectively.

In the years ended December 31, 2019 and 2018, impairment indicators were identified due to the reduction in contract opportunities, fall in market dayrates and contract terminations. We assessed recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilization of the units. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our drilling units, with sufficient headroom. As a result, we did not need to proceed to assess the fair values of our drilling units, and no impairment charges were recorded for the years ended December 31, 2019 and 2018.

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets which could materially affect our results of operations.

Income Taxes

Income tax expense is based on reported income or loss before income taxes.

Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. We do not conduct business or operate in the Republic of the Marshall Islands, and we are not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom, we are subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Significant judgment is involved in determining the provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence.

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax losses carried forward. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized.

We recognize liabilities for uncertain tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount that is more

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than 50% likely of being realized upon settlement. While we believe we have appropriate support for the positions taken on our tax returns, we regularly assess the potential outcomes of examinations by tax authorities in determining the adequacy of our provision for income taxes.

The determination and evaluation of our annual group income tax provision involves the interpretation of tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events, such as amounts, timing and the character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence. Changes in tax laws (such as the recent US tax reform), regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability materially in any given year.

While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as at the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities or valuation allowances. In addition, our uncertain tax positions are estimated and presented within other current liabilities, other liabilities, and as reductions to our deferred tax assets within our Consolidated Balance Sheets. For details on our tax position, refer to Note 7 - Taxation to the Consolidated Financial Statements included herein.

Recently Adopted and Issued Accounting Standards

For a discussion of recently adopted and recently issued accounting standards, please see Note 3 - "Recent accounting standards" to the Consolidated Financial Statements included herein.

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    A.     Operating Results

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

The following table summarizes our operating results for the years ended December 31, 2020 and 2019:

	Year Ended December 31,		Increase/(Decrease)
	2020	2019	$	%
(In $ millions)
Operating revenues:
Contract revenues	525.9	686.5	(160.6)	(23.4)	%
Reimbursable revenues	11.1	20.7	(9.6)	(46.4)	%
Other revenues	1.1	42.8	(41.7)	(97.4)	%
Total operating revenues	538.1	750.0	(211.9)	(28.3)	%
Operating expenses:
Vessel and rig operating expenses	(255.9)	(325.3)	69.4	21.3	%
Depreciation	(230.8)	(275.9)	45.1	16.3	%
Amortization of favorable contracts	(40.4)	(45.1)	4.7	10.4	%
Reimbursable expenses	(10.2)	(19.4)	9.2	47.4	%
Selling, general and administrative expenses	(34.4)	(34.4)	—	—	%
Total operating expenses	(571.7)	(700.1)	128.4	18.3	%
Other operating items:
Revaluation of contingent consideration	—	0.7	(0.7)	(100.0)	%
Impairment of long-lived assets	(4,210.4)	—	(4,210.4)	(100.0)	%
Total other operating (loss)/income	(4,210.4)	0.7	(4,211.1)	Nm
Operating (loss)/income	(4,244.0)	50.6	(4,294.6)	(8,487.4)	%
Financial items:
Interest income	6.1	20.3	(14.2)	(70.0)	%
Interest expense	(235.3)	(262.5)	27.2	10.4	%
Loss on derivative financial instruments	(16.1)	(27.7)	11.6	41.9	%
Currency exchange loss	(2.7)	(2.6)	(0.1)	(3.8)	%
Reorganization items, net	(49.8)	—	(49.8)	(100.0)	%
Other financial expenses	(17.1)	(1.4)	(15.7)	(1,121.4)	%
Total financial items	(314.9)	(273.9)	(41.0)	(15.0)	%
Loss before income taxes	(4,558.9)	(223.3)	(4,335.6)	(1,941.6)	%
Income tax (expense)/benefit	(30.0)	36.1	(66.1)	(183.1)	%
Net loss	(4,588.9)	(187.2)	(4,401.7)	(2,351.3)	%
Net loss attributable to Seadrill Partners LLC	(2,550.9)	(92.9)	(2,458.0)	(2,645.9)	%
Net loss attributable to the non-controlling interest	(2,038.0)	(94.3)	(1,943.7)	(2,061.2)	%

Contract revenues

Contract revenues were $525.9 million for the year ended December 31, 2020 (December 31, 2019: $686.5 million).

The $160.6 million or 23.4% decrease was primarily due to the West Capricorn ($100 million) and tender rigs ($52.7 million) being stacked. In addition, the West Aquarius, West Auriga and West Capella operated for fewer days ($19.8 million).

This was partly offset by more operating days for the West Polaris ($22.3 million) and higher economic utilization on the West Vela ($6.8 million).

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The following table summarizes our fleet's average daily contract revenues and economic utilization percentage by drilling unit type for the periods presented:

	Year Ended December 31,
	2020					2019
	Average number of rigs/ships on contract	Average Contractual Dayrate (1)		Economic Utilization (2)		Average number of rigs/ships on contract	Average Contractual Dayrate (1)		Economic Utilization (2)
Semi-submersible rigs	1	$	270,000	100.0	%	1	$	285,591	99.5	%
Drillship	4	$	386,504	97.0	%	3	$	427,931	91.2	%
Tender rigs	—	$	—	—	%	2	$	98,097	99.5	%

(1)We calculate the average contractual dayrate by dividing the aggregate contractual dayrates during a reporting period by the aggregate number of days for the reporting period.

(2)Economic utilization is calculated as the total revenue, excluding bonuses received, divided by the full operating dayrate multiplied by the number of days in the period for rigs on contract.

Reimbursable revenues

Reimbursable revenues were $11.1 million for the year ended December 31, 2020 (December 31, 2019: $20.7 million). The decrease of $9.6 million, or 46.4%, was due to fewer equipment purchases being made on behalf of customers under the reimbursable arrangements in our drilling contracts.

Other revenues

Other revenues were $1.1 million for the year ended December 31, 2020 (December 31, 2019: $42.8 million).

The $41.7 million or 97.4% decrease was primarily due early termination revenue in 2019 for the West Capricorn ($29 million) and West Vencedor ($11 million) not repeated in 2020.

Vessel and rig operating expenses

Vessel and rig operating expenses were $255.9 million in the year ended December 31, 2020 (December 31, 2019: $325.3 million).

The $69.4 million or 21.3% decrease was primarily due to the West Capricorn, West Vencedor and tender rigs being stacked ($57.4 million); fewer operating days for the West Aquarius, West Auriga and West Capella ($20.3 million) and rig move costs for the West Leo ($10.4 million). This was partially offset by more operating days for the West Polaris ($14.5 million) and higher R&M project spend for the West Vela ($3.1 million).

Depreciation

Depreciation was $230.8 million for the year ended December 31, 2020 (December 31, 2019: $275.9 million). The $45.1 million or 16.3% decrease was primarily due to lower depreciation on West Leo, West Sirius and West Vencedor due to impairments recognized in March 2020.

Reimbursable expenses

Reimbursable expenses were $10.2 million for the year ended December 31, 2020 (December 31, 2019: $19.4 million). The $9.2 million or 47.4% decrease was in line with the reduction in reimbursable revenue.

Impairment of long-lived assets

In 2020, we recognized an impairment of $4,210.4 million in respect of all of our drilling units, with two drilling units fully impaired. For further information refer to Note 10 - "Impairment of long-lived assets" to the Consolidated Financial Statement included herein. There was no impairment of long-lived assets during the year ended December 31, 2019.

Interest income

Interest income was $6.1 million for the year ended December 31, 2020 (December 31, 2019: $20.3 million). The $14.2 million or 70.0% decrease was primarily due to a decrease in cash balances and LIBOR rates in 2020.

Interest expense

Interest expense was $235.3 million for the year ended December 31, 2020 (December 31, 2019: $262.5 million). The decrease of $27.2 million or 10.4% is primarily due to no interest recognized for December 2020 following the filing for Chapter 11 and a reduction in the average 3-month LIBOR rates. This has been offset by amortization of loan fees relating to the new super senior loans. Refer to Note 4 - "Chapter 11 Proceeding" to the Consolidated Financial Statements included herein.

Loss on derivative financial instruments

Derivative financial items resulted in a loss of $16.1 million for the year ended December 31, 2020 (December 31, 2019: loss of $27.7 million). The $11.6 million or 41.9% decrease is due to a decrease in the forward interest rates and payment default in the fourth quarter of 2020 relating to the Chapter 11 filing.

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Currency exchange loss

Loss on foreign currency exchange was $2.7 million for the year ended December 31, 2020 (December 31, 2019: loss of $2.6 million).

Reorganization items, net

Expenses and income directly associated with Chapter 11 in 2020, comprised of a write-off of unamortized debt issuance costs ($42.9 million), post-filing professional and advisory fees incurred ($7.1 million) and interest income on surplus cash invested ($0.2 million).

Other financial expenses

Other financial expenses were $17.1 million for the year ended December 31, 2020 (December 31, 2019: $1.4 million expense). The 2020 balance relates to professional and advisory fees incurred pre-filing ($9.5 million) and the reversal of credit risk on derivatives ($7.1 million).

Income tax expense/benefit

Income tax was an expense of $30.0 million for the year ended December 31, 2020 (December 31, 2019: $36.1 million benefit) and the effective income tax rate was negative 0.7% and positive 16.2% for the years ended December 31, 2020 and 2019 respectively. The unfavorable movement primarily relates to an U.S. BEAT adjusted for expense for CARES compared to a benefit in 2019. Please refer to Note 7 - "Taxation" to the Consolidated Financial Statements included herein for further information.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The following table summarizes our operating results for the years ended December 31, 2019 and 2018:

(In $ millions)	Year Ended December 31,		Increase/(Decrease)
	2019	2018	$	%
Operating revenues:
Contract revenues	686.5	797.5	(111.0)	(13.9)	%
Reimbursable revenues	20.7	31.2	(10.5)	(33.7)	%
Other revenues	42.8	209.5	(166.7)	(79.6)	%
Total operating revenues	750.0	1,038.2	(288.2)	(27.8)	%
Operating expenses:
Vessel and rig operating expenses	(325.3)	(278.2)	(47.1)	(16.9)	%
Amortization of favorable contracts	(45.1)	(45.1)	—	—	%
Reimbursable expenses	(19.4)	(28.6)	9.2	32.2	%
Depreciation	(275.9)	(280.3)	4.4	1.6	%
Selling, general and administrative expenses	(34.4)	(45.8)	11.4	24.9	%
Total operating expenses	(700.1)	(678.0)	(22.1)	(3.3)	%
Other operating items:
Revaluation of contingent consideration	0.7	—	0.7	100.0	%
Loss on impairment of goodwill	—	(3.2)	3.2	100.0	%
Total other operating income/(loss)	0.7	(3.2)	3.9	121.9	%
Operating income	50.6	357.0	(306.4)	(85.8)	%
Financial items:
Interest income	20.3	47.1	(26.8)	(56.9)	%
Interest expense	(262.5)	(263.7)	1.2	0.5	%
(Loss)/Gain on derivative financial instruments	(27.7)	24.9	(52.6)	(211.2)	%
Currency exchange (loss)/gain	(2.6)	0.2	(2.8)	(1,400.0)	%
Other financial items	(1.4)	(4.8)	3.4	70.8	%
Total financial items	(273.9)	(196.3)	(77.6)	(39.5)	%
(Loss)/income before income taxes	(223.3)	160.7	(384.0)	(239.0)	%
Income tax benefit/(expense)	36.1	(86.7)	122.8	141.6	%
Net (loss)/income	(187.2)	74.0	(261.2)	(353.0)	%
Net (loss)/income attributable to Seadrill Partners LLC	(92.9)	56.1	(149.0)	(265.6)	%
Net (loss)/income attributable to the non-controlling interest	(94.3)	17.9	(112.2)	(626.8)	%

Contract revenues

Contract revenues were $686.5 million, for the year ended December 31, 2019 (December 31, 2018: $797.5 million).

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The $111 million or 13.9% decrease was primarily due to the West Capricorn ($110 million) operating at a lower dayrates on new contracts and having fewer operating days as a result of the early termination of its contract with BP. In addition, the West Aquarius ($16.4 million) operated for fewer days, the T16 ($24.9 million) and T15 ($9 million) completed contracts with Chevron and the West Auriga ($7.3 million) experienced downtime for unplanned maintenance.

This was partly offset by more operating days for the West Polaris ($22.4 million), West Capella ($15 million) and West Vencedor ($11.6 million), and higher economic utilization on the West Vela ($7.5 million).

The following table summarizes our fleet's average daily contract revenues and economic utilization percentage by drilling unit type for the periods presented:

	Year Ended December 31,
	2019					2018
	Average number of rigs/ships on contract	Average Contractual Dayrate (1)		Economic Utilization (2)		Average number of rigs/ships on contract	Average Contractual Dayrate (1)		Economic Utilization (2)
Semi-submersible rigs	1	$	285,591	99.5	%	2	$	423,650	99.8	%
Drillship	3	$	427,931	91.2	%	2	$	491,459	92.7	%
Tender rigs	2	$	98,097	99.5	%	2	$	110,722	98.6	%

(1)We calculate the average contractual dayrate by dividing the aggregate contractual dayrates during a reporting period by the aggregate number of days for the reporting period.

(2)Economic utilization is calculated as the total revenue, excluding bonuses received, divided by the full operating dayrate multiplied by the number of days in the period for rigs on contract.

Reimbursable revenues

Reimbursable revenues were $20.7 million, for the year ended December 31, 2019 (December 31, 2018: $31.2 million). The decrease of $10.5 million or 33.7% was due to fewer equipment purchases being made on behalf of customers under the reimbursable arrangements in our drilling contracts.

Other revenues

Other revenues were $42.8 million for the year ended December 31, 2019 (December 31, 2018: $209.5 million).

The $166.7 million or 79.6% decrease was primarily due to the West Leo litigation judgment in our favor recognized in 2018 ($205 million). Please refer to Note 22 - "Commitments and contingencies" to the Consolidated Financial Statements included herein. This was partially offset by early termination revenue in 2019 for the West Capricorn ($29 million) and West Vencedor ($11.0 million).

Vessel and rig operating expenses

Vessel and rig operating expenses were $325.3 million, for the year ended December 31, 2019 (December 31, 2018: $278.2 million).

The $47.1 million or 16.9% increase was primarily due to an increase in operating days for the West Polaris ($16.1 million), West Vencedor ($10.7 million), West Capella ($8.2 million) and increased R&M and personnel costs on the West Vela ($5.4 million), partially offset by decreased operating days for the T16 ($4.3 million). In addition, there was a change in classification of certain operational support costs in 2019, which increased vessel and rig expenses ($11.4 million) and reduced selling, general and administrative expenses (see "Selling, general and administrative expenses" below).

Reimbursable expenses

Reimbursable expenses were $19.4 million for the year ended December 31, 2019 (December 31, 2018: $28.6 million). The $9.2 million or 32.2% decrease is in line with the reduction in reimbursable revenue.

Depreciation

Depreciation was $275.9 million for the year ended December 31, 2019 (December 31, 2018: $280.3 million). The $4.4 million or 1.6% decrease was primarily due to lower depreciation expense on the West Sirius and West Aquarius due to certain long-term maintenance projects becoming fully depreciated during the year.

Selling, general and administrative expenses

Selling, general and administrative expenses were $34.4 million for the year ended December 31, 2019 (December 31, 2018: $45.8 million). The $11.4 million or 24.9% decrease is primarily due to the change in the classification of certain operational support costs referenced above (see "Vessel and rig operating expenses" above).

Loss on impairment of goodwill

In 2018, we recognized a loss of $3.2 million due to the early adoption of ASU 2017-04, Intangibles. For further information refer to Note 3 - "Recent accounting standards" to the Consolidated Financial Statements included herein. There was no loss on impairment of goodwill during the year ended December 31, 2019.

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Interest income

Interest income was $20.3 million for the year ended December 31, 2019 (December 31, 2018: $47.1 million). The $26.8 million or 56.9% decrease was primarily due to interest related to the West Leo litigation judgment in 2018 ($24 million). The residual relates to a decrease in LIBOR rates in 2019.

Loss/gain on derivative financial instruments

Derivative financial items resulted in a loss of $27.7 million for the year ended December 31, 2019 (December 31, 2018: gain of $24.9 million). The $52.6 million change was due to a decrease in the forward interest rates.

Currency exchange loss/gain

Loss on foreign currency exchange was $2.6 million for the year ended December 31, 2019 (December 31, 2018: gain of $0.2 million).

Other financial items

Other financial items resulted in an expense of $1.4 million for the year ended December 31, 2019 (December 31, 2018: $4.8 million expense). The expense in 2018 relates to legal and agent fees for the TLB leverage covenant waiver ($3.6 million). The 2019 balance relates to several immaterial fees across the group.

Income taxes

Income tax was a credit of $36.1 million for the year ended December 31, 2019 (December 31, 2018: $86.7 million expense) and the effective income tax rate was 16.2% and 54% for the years ended December 31, 2019 and 2018 respectively. The favorable movement primarily relates to the reversal of an uncertain tax position recorded in 2018, following guidance from the U.S. Department of Treasury. Please refer to Note 7 - "Taxation" to the Consolidated Financial Statements included herein for further information.

    B.     Liquidity and Capital Resources

Overview

We operate in a capital-intensive industry, and our primary uses of liquidity are servicing our debt, financing maintenance and capital expenditure on drilling units, funding working capital and maintaining cash reserves against fluctuations in operating cash flows.

Most of our contract and other revenues are received monthly in arrears, and most of our operating costs are paid monthly in arrears. Our funding and treasury activities are conducted within corporate policies to maximize returns while maintaining appropriate liquidity for our operating requirements.

This section discusses the most important factors affecting our liquidity and capital resources, including:

•Liquidity requirements

•Estimated maintenance and replacement capital expenditures

•Analysis of cash flows for the years ending December 31, 2020, 2019 and 2018

•Borrowing activities

•Restrictive covenants

•Derivative instruments and hedging activities.

Liquidity Requirements

Our primary short-term liquidity requirements relate to servicing our debt, funding working capital requirements, paying for capital expenditures on drilling unit upgrades and major maintenance. Our main sources of liquidity include cash deposits and contract and other revenues. As of December 31, 2020, we had cash and cash equivalents, including restricted cash of $378.4 million, compared to $560.0 million as of December 31, 2019.

Bankruptcy proceedings and going concern position

Since the mid-2010s, the industry has experienced a sustained decline in oil prices which has culminated in an industry-wide supply and demand imbalance. During this period, market dayrates for drilling rigs have been lower than was anticipated when the debt associated with acquiring our rigs was incurred. This challenging business climate was further destabilized by challenges that have arisen due to the COVID-19 pandemic. The actions taken by governmental authorities around the world to mitigate the spread of COVID-19 have had a significant negative effect on oil consumption. This has led to a further decrease in the demand for our services and has had an adverse impact on our business and financial condition.

On December 1, 2020 Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petition for reorganization under Chapter 11 triggering a stay on enforcement of remedies with respect to our debt obligations. As part of the Chapter 11 proceedings, the Debtors were granted “first-day” relief which enables us to continue operations without interruption. On February 12, 2021, the Debtors and certain of their prepetition lenders executed a plan support agreement, which contemplates a series of restructuring transactions that will equitize approximately $2.7 billion in secured term loan obligations and select go-forward, value maximizing services providers.

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As of December 31, 2020, we had cash and cash equivalents of $378.4 million of which $362.0 million was unrestricted and we have implemented, and will continue to implement, various measures to preserve liquidity. These include primarily deferrals of capital expenditures and cold stacking the drilling units, as well as an increased focus on operating efficiency and reductions in corporate and overhead expenditures. Whilst we believe this should provide sufficient liquidity to allow us to complete a comprehensive restructuring, the process is difficult to predict and subject to factors outside of our control. We are subject to numerous risks associated with the bankruptcy proceedings and there can be no assurance that we will agree upon a plan of reorganization that is acceptable to our creditors, nor that the Bankruptcy Court would confirm such a plan once agreed.

These conditions and events raise substantial doubt as to our ability to continue as a going concern for the twelve months after the date our financial statements are issued. Financial information in this report has been prepared on a going concern basis of accounting, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Financial information in this report does not reflect the adjustments to the carrying values of assets, liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.

Restrictions on distributions

Our cash distribution policy is described in Item 8 - "Financial Information".

In addition, in February 2018, we completed an amendment to the terms of our Term Loan B ("TLB"). In connection with the waiver, we agreed that our quarterly distributions would not exceed 10 cents per common unit unless the Consolidated net leverage ratio is below 4x during 2018 and below 5x thereafter. Please read Note 16 - "Debt" to the Consolidated Financial Statements included herein for further details.

Estimated Maintenance and Replacement Capital Reserves

In determining the amount of cash available for distribution, the Board determines the amount of cash reserves to set aside, including reserves for future maintenance capital expenditures, working capital and other matters. Because of the substantial capital expenditures we are required to make to maintain our fleet, our current annual estimated maintenance and replacement capital reserves are $238 million per year, which is comprised of $75 million for long term maintenance and society classification surveys and $163 million, including financing costs, for replacing our existing drilling units at the end of their useful lives.

The estimate for future rig replacement is based on assumptions regarding the remaining useful life of our drilling units, a net investment rate applied on reserves, replacement values of our existing rigs based on current market conditions, and the residual value of the rigs. The actual cost of replacing the drilling units in our fleet will depend on a number of factors, including prevailing market conditions, drilling contract operating dayrates and the availability and cost of financing at the time of replacement. Our operating agreement requires the Board to deduct from the Company's operating surplus each quarter estimated maintenance and replacement capital reserves, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as society classification surveys and rig replacement. The Board, with the approval of the conflicts committee, may determine that one or more of the assumptions should be revised, which could cause the Board to increase the amount of estimated maintenance and replacement capital reserves. As our fleet matures, estimated long-term maintenance reserves will likely increase.

Analysis of Cash Flows for the years ending December 31, 2020, 2019 and 2018

The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the periods presented:

(In $ millions)	Year Ended December 31,
	2020	2019	2018
Net cash provided by/(used in) operating activities	165.0	(26.0)	434.1
Net cash used in investing activities	(9.4)	(29.7)	(23.4)
Net cash used in financing activities	(337.2)	(225.9)	(416.7)
Effect of exchange rate changes on cash	—	—	(1.0)
Net decrease in cash and cash equivalents	(181.6)	(281.6)	(7.0)
Cash and cash equivalents at beginning of period	560.0	841.6	848.6
Cash and cash equivalents, including restricted cash, at the end of year	378.4	560.0	841.6

Net cash provided by/used in operating activities

Market conditions in the offshore drilling industry in recent years have led to materially lower levels of spending for offshore exploration and development. This has negatively affected our revenues, profitability and operating cash flows. During the year ended December 31, 2020 cash provided by operating activities was $165 million. This was primarily due to unpaid TLB interest since June 2020 and final dayrate receipts as a result of the completion of the West Auriga and West Aquarius contracts.

In the year ended December 31, 2019 net cash of $26 million was used in operating activities whilst for the year ended December 31, 2018 net cash of $434.1 million was provided from operating activities. The adverse movement of $460.1 million was primarily due to lower revenue as a result of the completion of the West Capricorn, T-15 and T-16 legacy contracts and settlement of overdue related party trade balances leading to a cash outflow from operating activities during the year ended December 31, 2019.

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Net cash used in investing activities

Net cash used in investing activities was $9.4 million for the year ended December 31, 2020, primarily related to capital expenditures on the West Auriga, West Polaris, West Vela and West Capricorn.

Net cash used in investing activities was $29.7 million for the year ended December 31, 2019, primarily related to capital expenditures on the West Aquarius, West Vela, and West Polaris.

Net cash used in investing activities was $23.4 million for the year ended December 31, 2018, primarily related to a managed pressure drilling system for the West Capricorn and upgrades to the blow out preventer for the West Auriga and West Aquarius.

Net cash used in financing activities

Net cash used in financing activities was $337.2 million for the year ended December 31, 2020. This was due to external debt repayments of $306.6 million and payments of deferred and contingent consideration of $30.6 million.

Net cash used in financing activities was $225.9 million for the year ended December 31, 2019. This was due to external debt repayments of $192.6 million, payments of deferred and contingent consideration of $30 million and cash distributions of $3.3 million.

Net cash used in financing activities was $416.7 million for the year ended December 31, 2018. This was due to external debt repayments of $296.4 million, related party debt repayments of $24.7 million, payments of deferred and contingent consideration of $34.0 million, repayment of shareholder loan of $6.2 million and cash distributions of $55.4 million.

Net decrease in Cash and cash equivalents

As a result of the above, cash and cash equivalents decreased by $181.6 million in 2020, $281.6 million in 2019 and by $7 million in 2018.

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Borrowing Activities

The below table summarizes the status of our borrowing facilities at December 31, 2020 and December 31, 2019.

Facility	Collateral Vessels	Maturity	Principal outstanding at December 31,		Debt repayments
(In $ millions)			2020	2019	2020	2019
External facilities
Term loan B	See below (1)	Feb-2021	2,727.1	2,607.6	22.1	28.8
$100m RCF	See below (1)	Feb-2019	—	—	—	50.0
West Vela facility	West Vela	Oct-2020	—	151.0	151.0	40.3
West Polaris facility	West Polaris	Jul-2020	—	114.9	114.9	35.9
Tender Rig facility	T-15 & T-16	Apr-2020	—	18.6	18.6	37.6
Total			2,727.1	2,892.1	306.6	192.6
Less: Debt balance held as subject to compromise			(2,727.1)	—	—	—
Debt balance not subject to compromise			—	2,892.1	306.6	192.6

(1) Following an amendment to the TLB agreement, and repayment of the other loan facilities (see above), all rigs are pledged as collateral vessels under the TLB.

Key changes to borrowing facilities from January 1, 2019 to December 31, 2020

We filed for Chapter 11 bankruptcy protection on December 1, 2020 which triggered an event of default under the TLB. As a result, the outstanding balance on this loan was classified within "liabilities subject to compromise" on the Consolidated Balance Sheets at December 31, 2020. For further information of our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings" to our Consolidated Financial Statements included herein.

On filing for Chapter 11, $42.9 million of unamortized debt issuance costs on the TLB were expensed and recognized within "Reorganization items, net" in the Consolidated Statement of Operations and no further interest was recorded on the Term Loan B from that point.

We agreed with the TLB lenders to amend the TLB agreement in July and October 2020 respectively, whereby the majority of the TLB interest that was due on June 30, 2020 and September 30, 2020 was converted into super senior loans ($8 million of TLB interest was cash settled to lenders that withheld consent). As a result, $63.7 million and $63.3 million super senior loans, maturing in February 2021 were created. These loans each include a non-cash $20 million commitment fee and an exit fee of 10% in addition to the interest settled through issuance of the loans.

We had a total of $2,727.1 million outstanding on the TLB at December 31, 2020.

The Tender Rig facility includes a "satisfactory drilling contract" covenant. As a consequence of the T-16 and T-15 not having a satisfactory drilling contract for a period of time, the facility comes due on a pro rata basis. $20.0 million of the outstanding bank debt relating to the T-16 was repaid in November 2019. The remaining $2.7 million and $15.9 million balloon payment relating to the T-15 was repaid in March and April 2020 respectively.  

The remaining $120.8 million and $93.8 million balloon payments for the West Vela and West Polaris facilities were repaid in July 2020.

Debt issuance costs

In our Consolidated Balance Sheets we present debt balances net of debt issuance costs. This is set out in the below table:

	Outstanding debt as at December 31, 2020
(In $ millions)	Principal outstanding	Debt Issuance Costs (1)	Total Debt
Debt held as subject to compromise	2,727.1	—	2,727.1
Total interest-bearing debt	2,727.1	—	2,727.1

	Outstanding debt as at December 31, 2019
(In $ millions)	Principal outstanding	Debt Issuance Costs	Total Debt
Current portion of long-term external debt	313.3	(11.9)	301.4
Long-term external debt	2,578.8	(2.0)	2,576.8
Total interest-bearing debt	2,892.1	(13.9)	2,878.2

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(1) On filing for Chapter 11 on December 1, 2020 all unamortized debt issuance costs on under-secured debt have been written off to "reorganization items, net" in our Consolidated Statement of Operations. For further details refer to Note 4 - "Chapter 11 Proceedings" to the Consolidated Financial Statements included herein.

Further information

Please refer to Note 16 - "Debt" to the Consolidated Financial Statements included herein for detailed information on our borrowings and credit facilities.

Restrictive Covenants

Details of covenants, terms of default and restrictions may be found in the debt agreement and subsequent amendments which have been filed as exhibits to this report on Form 20-F. Please refer to Item 19 - "Exhibits".

On December 1, 2020, the lenders have agreed to waive any breach of, or default under, our debt agreements after this date, which arise as a result of or is, directly or indirectly, related to the commencement of Chapter 11 proceedings. Please refer to Note 16 – "Debt" to our Consolidated Financial Statements included herein for further information on the impact on our covenants contained within our credit facilities.

Solely as a result of our commencing negotiations with our creditors, we have reached agreement with certain lenders to limit our access to certain cash collateral accounts to funding related to operations, capital expenditures and debt service. We are engaged in discussions with such lenders regarding the cash collateral accounts and do not expect any interruption to our operations or a material adverse effect on our liquidity.

Derivative Instruments and Hedging Activities

We may use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. Our use of these instruments is described below.

Interest rate risk

Due to the filing of the Bankruptcy Petitions, interest is no longer incurred on our debt facilities. Prior to filing for Chapter 11, we entered into a derivative agreement (interest rate swap) to mitigate the risk of interest rate fluctuations. None of our interest rate swaps were designated as hedging instruments. Therefore, changes in their fair value were taken to income each period. We classified the gain or loss on interest rate swaps within the line item "(loss)/gain on derivative financial instruments" in the Consolidated Statements of Operations.

We defaulted on payments due on the interest rate swaps on November 23, 2020 in preparation for the Chapter 11 filing. On December 1, 2020 the interest rate swaps were terminated. Please refer to Note 20 - "Risk management and financial instruments" for further details.

Prior to this default, on November 23, 2020, our interest rate swap contracts had a combined outstanding principal amount of $2,714.1 million (December 31, 2019: $2,735.8 million), swapping LIBOR for an average fixed rate of 2.49% per annum.

As of December 31, 2019, our net exposure to short term fluctuations in interest rates on our outstanding debt was $156.3 million, based on total net interest bearing debt of $2,892.1 million, less the $2,735.8 million outstanding balance of fixed interest rate swaps.

Foreign currency risk

Our cash and cash equivalents are held primarily in U.S. Dollars with minor balances held in other currencies. Our revenue and costs are primarily denominated in U.S. Dollars although a proportion of our vessel and rig operating expenses and a small amount of revenue are denominated in other currencies. The main currencies in which we have foreign currency exposures are Canadian Dollars, Thai Baht, Nigerian Naira and Malaysian Ringgit.

We do not currently use derivative instruments to manage currency risk. However, depending on the level of our currency exposure, we may do so in the future.

    C.     Research and Development, Patents and Licenses

We do not undertake any significant research and development activities.

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    D.     Trend Information

The below table show the average oil price over the period 2016 to 2020. The Brent crude oil price at March 31, 2021 was $64.

	2016	2017	2018	2019	2020
Average Brent crude oil price ($/bbl)	45	55	71	64	42

Although we saw Brent prices stabilize between 2018-2019, the oil price plummeted in 2020 creating significant uncertainty on the Oil and Gas industry’s trajectory for 2021. The global impacts surrounding the COVID-19 outbreak and the oil price war between Saudi Arabia and Russia impacted in a substantial decline in Brent price. While the global demand for oil has partially rebounded it remains well below the pre-pandemic levels. The sustained low level of oil price has materially affected the drilling industry and the financial condition of drilling contractors. We expect this volatility to continue and if the price of oil declines further and/or remains at a low price for an extended period there could be further material effect on our business, financial condition and results of operations.

The below table shows the global number of rigs on contract and marketed utilization at December 31, 2020 and for each of the four preceding years.

	2016		2017		2018		2019		2020
Contracted rigs
Harsh environment floater	35		30		31		35		25
Benign environment floater	139		120		116		119		119
Tender	20		16		14		14		13
Marketed utilization
Harsh environment floater	81	%	83	%	85	%	87	%	77	%
Benign environment floater	71	%	71	%	73	%	77	%	77	%
Tender	66	%	60	%	62	%	65	%	63	%

Floater

During the first two months of 2020 there continued to be an increase in the number of opportunities for floaters and net floater supply continued to decline which improved utilization. However, the pandemic and the drop in oil prices impacted the utilization levels. The drop in marketed utilization of the benign floater was not as stark as initially anticipated mainly due to units being cold stacked and increased attrition. The drop in utilization was greater in the harsh environment floater segment as it was further along in the recovery than the benign environment. Consequently, there was a larger number terminations and more units rolling off contracts with no follow on work. Lower attrition and less cold stacking also contributed to drop in marketed utilization levels.

There is still considerable imbalance between supply and demand across the floater segment applying downward pressure on the utilization levels and dayrates. With conservative capex spend estimated among oil companies we expect the recovery to be slow over the coming quarters, unless there is a surge in post-COVID oil demand.

Tender rigs

The tender rig market is less fragmented and more localized than the floater market with activity focused primarily in South-east Asia and West Africa. The utilization levels in 2020 declined slightly as a consequence of the pandemic and the drop in oil prices. Continued low utilization levels has kept dayrates competitive.

    E.     Safe Harbor

See the section entitled "Important Information Regarding Forward-Looking Statements" in this annual report.

Item 6.         Directors, Senior Management and Employees

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    A.     Directors and Senior Management

Directors

The following provides information about each of the Company's directors. The business address through which the Board can be contacted is 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.

Name	Position
Anthony R. Horton	Director and Conflicts Committee Member
Andrew Cumming	Director, Compensation Committee and Conflicts Committee Member
John Darlington	Director, Audit Committee and Conflicts Committee Member
John T. Roche	Director, Chief Executive Officer and Chief Financial Officer
Keith MacDonald	Director, Audit Committee, Compensation Committee and Conflicts Committee Member
Leif Nelson	Director and Compensation Committee Member
Gunnar Winther Eliassen	Director

Certain biographical information about each of our directors and executive officers is set forth below.

Anthony R. Horton was appointed to the board of directors by the elected directors in January 2020 as an elected director. Mr. Horton also serves on the Company's conflicts committee. Mr. Horton is a senior executive with more than 20 years of experience in the energy industry, most recently as Chief Financial Officer of Energy Future Holdings. Currently, Mr. Horton chairs and serves as a director of Toro Private Holdings III, Ltd, Miroposa Intermediate Holdings, LLC, NanoLumens, LLC, Frontera Holdings, LLC, Arena Energy GP, LLC and has a strong track record in capital markets, operations, mergers and acquisitions.

Andrew Cumming was originally appointed to the board of directors by the elected directors in June 2015 and was elected by the unitholders in September 2016. Mr. Cumming also serves on the Company's compensation and conflicts committees. Mr. Cumming has over 40 years of experience in banking and risk management. Prior to his retirement in 2014, Mr. Cumming spent 17 years of his career in a variety of senior positions at Lloyds Bank, including Chief Credit Officer, Commercial Banking Division, Managing Director, Global Non Core Division and membership of Group Risk and Commercial Banking Executive Committees. He is a graduate of the University of London and a Fellow of the Chartered Institute of Bankers Scotland. Mr. Cumming also currently acts as a director of a mortgage company, Bluestone Holdings Group, a private equity company, Lloyds Development Capital and a publishing company, The Quarto Group Inc.

John Darlington was originally appointed to the board of directors by the Seadrill Member in December 2018 and was appointed by the elected directors in January 2020 as an elected director. Mr. Darlington also serves on the Company's audit and conflicts committees. Mr. Darlington's previous experience includes serving as a Partner of KPMG from 2006 to 2013. He was Executive Chairman of Linpac Group Holdings Ltd. (2010-2012), a multinational packaging group, and Executive Chairman of Sunseeker International Ltd. (2009-2010), the luxury yacht manufacturer. He has significant experience of stakeholder management, public relations and acquisitions and disposals.

John T. Roche was appointed to the board of directors by the Seadrill Member in June 2019 and has served as the Chief Executive Officer since June 2019 and Chief Financial Officer since March 2020. Mr. Roche was formerly Chief Financial Officer of the Company from June 2015 to June 2019. From 2013 to March 2020, Mr. Roche served as Vice President of Corporate Finance and Investor Relations for Seadrill. Prior to joining Seadrill in May 2013, Mr. Roche spent 12 years at Morgan Stanley, most recently as an Executive Director in its Investment Banking Division and is a Chartered Financial Analyst.

Keith MacDonald was originally appointed to the board of directors by the Seadrill Member in October 2014 and was elected by the unitholders in September 2016. Mr. MacDonald also serves on the Company's audit, compensation and conflicts committees. Mr. MacDonald has over 30 years of experience in asset finance as an adviser, banker and independent board director. From 2009 to 2013 he was Global Head of Structured Corporate Finance for Lloyds Banking Group which included the Shipping and other asset finance operations of the Bank. Prior to Lloyds he held senior roles for Citibank from 1990 to 2006 culminating in being Asia-Pacific Head of Structured Corporate Finance based in Hong Kong and was extensively involved in the Bank's ship finance activities for the Asian market. From 2006 to 2009 he was a Founding Partner of Manresa Partners, a London-based Corporate Finance boutique that specialized in cross-border asset financing. Mr. MacDonald currently acts as an adviser to a number of companies and financial institutions. He is also an Independent Director of three aircraft finance entities and is a Non-Executive Director of First Derivatives plc, a FinTech company listed in London and Dublin. He is a graduate of the National University of Ireland, a Fellow of the Institute of Chartered Accountants in Ireland and a Chartered Director.

Leif Nelson was appointed to the board of directors by the Seadrill Member in June 2019. Since 2015, Mr. Nelson has served as Chief Operating Officer for Seadrill and has over 18 years' experience in the drilling industry. Prior to joining Seadrill, Mr. Nelson has held various operational roles for Transocean Ltd and sits on the Executive Committee of the International Association of Drilling Contractors. Mr. Nelson is a graduate of the Colorado School of Mines and holds a BSc in Petroleum Engineering. Mr. Nelson also sits on the board of the Well Control Institute.

Gunnar Winther Eliassen was appointed as Director on February 27, 2020. Mr. Eliassen has been employed by Seatankers Consultancy Services since January 2016. Mr. Eliassen also serves as a Director of Seadrill Limited, Golden Close Maritime Corp. Ltd. and KLX Energy Services Inc. Mr. Eliassen was also a Partner at Pareto Securities In. in New York and Oslo. Mr. Eliassen obtained an MBA in Finance from the Norwegian School of Economics.

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Senior Management

The names of the members of management as of March 31, 2021 and their respective positions, are presented in the table below:

Name	Position
John T. Roche	Chief Executive Officer, Chief Financial Officer
Mo Meghji	Chief Restructuring Officer
Emma Li	Finance Director

John T. Roche has served as Chief Executive Officer since June 2019 and Chief Financial Officer since March 2020. For further information on Mr. Roche, please refer to his biography within 'Directors' above. The individuals who are responsible for the Company's day-to-day management are subject to the direction of the Board. The business address for the Company's executive officer is 2nd Floor, Building 11, Chiswick Business Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.

Mo Meghji was appointed as Chief Restructuring Officer in October 2020. Mr. Meghji is the Managing Partner of M-III Partners, LP, and is a nationally recognized U.S. turnaround professional with an exemplary track record of accomplishment across a wide range of industries. He has over 30 years' experience, focused primarily on reviving companies experiencing financial, operational or strategic transitions to maximize value for stakeholders. Prior to founding M-III Partners, LP, Mr. Meghji served as Executive Vice President & Head of Strategy at Springleaf Holdings, LLC as well as CEO of its captive insurance companies. Mr. Meghji has recently served as a director on corporate boards of, among others, Frontier Communications, Toys “R” Us, Philadelphia Energy Solutions Refining and Marketing LLC and SHOPKO Corporation. Mr. Meghji is a graduate of the Schulich School of Business, York University, Canada and has taken executive courses at the INSEAD School of Business in France. He has qualified as a U.K. and Canadian Chartered Accountant as well as a U.S. Certified Turnaround Professional.

Emma Li has served as Finance Director since March 2020. Ms Li was previously Head of Corporate Finance and Investor Relations and worked in Mergers and Acquisitions for Seadrill Limited. Prior to joining Seadrill Ms Li spent 4 years working in Energy and Resources in Deloitte LLP and is also a Chartered Accountant (ACA).

    B.     Compensation

Executive Compensation

We are managed on a day to day basis by our executive officers. As set out in ITEM 6A, this consists of John Roche, Mo Meghji, Emma Li. Please read Item 7 - "Major Unitholders and Related Party Transactions - B. Related Party Transactions" for further details on this agreement. For the year ended December 31, 2020, Executive Management received aggregate compensation of $1.4 million.

Directors Appointed by Seadrill Member

Three of our Directors, Leif Nelson, Gunnar Winther Eliassen and John Roche, were appointed to the Board by the Seadrill Member. We pay these Directors for their service as Directors, and we reimburse out-of-pocket expenses incurred attending meetings of the Board or its committees.

For the year ended December 31, 2020, Seadrill appointed Directors received aggregate compensation for services of $0.1 million. In addition, we reimbursed each of these Directors for out-of-pocket expenses incurred attending meetings of the Board or its committees.

Directors Elected by Common Unit Holders

Four of our Directors, John Darlington, Anthony Horton, Andrew Cumming, and Keith MacDonald are elected members and are therefore subject to reappointment by rotation at the annual meeting of unitholders. We pay these Directors, and we reimbursed them for out-of-pocket expenses incurred attending meetings of the Board or its committees.

For the year ended December 31, 2020, the Directors elected by common unitholders received aggregate compensation for services of $0.8 million.

Indemnification

We fully indemnify each Director for actions associated with being a Director to the extent permitted under Marshall Islands law.

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    C.     Board Practices

General

Our operating agreement provides that the Board has authority to oversee and direct our operations, management and policies on an exclusive basis. The executive officers manage our day-to-day activities consistent with the policies and procedures adopted by the Board. Certain of our current directors are also executive officers or directors of Seadrill.

Our current Board consists of seven members: Andrew Cumming, Anthony Horton, John Darlington, Keith MacDonald, Leif Nelson, John Roche and Gunnar Winther Eliassen. The Board has determined that each of Mr. Darlington, Mr. Horton, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by NYSE and Rule 10A-3 of the Exchange Act. Mr. Darlington was originally appointed by the Seadrill Member and in January 2020 was reappointed to the board as an elected director to fill a casual vacancy. Mr. Horton, Mr. Cumming and Mr. MacDonald are subject to election by our common unitholders.

Directors elected by our common unitholders are divided into three classes serving staggered three-year terms. Mr. Darlington is designated as the Class I elected director and will serve until the annual meeting of unitholders in 2020. Mr. Horton is designated as the Class II elected director and will serve until the annual meeting of unitholders in 2021. Each of Mr. MacDonald and Mr. Cumming is designated as a Class III elected director and will serve until the annual meeting of unitholders in 2023.

At each annual meeting of unitholders, directors will be elected to succeed the class of directors whose terms have expired by a plurality of the votes of the common unitholders. Directors elected by the common unitholders will be nominated by the Board or by any member or group of members that holds at least 10% of the outstanding common units.

Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, if at any time, any person or group owns beneficially more than 5% or more of any class of units then outstanding, any such units owned by that person or group in excess of 5% may not be voted (except for purposes of nominating a person for election to the Board). The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of such class of units. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of its board of directors is not subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.

Committees

We have an audit committee that, among other things, reviews our external financial reporting, engages external auditors and oversees its internal audit activities and procedures and the adequacy of its internal accounting controls. The audit committee is currently composed of two directors, Mr. Darlington and Mr. MacDonald. Mr. Darlington and Mr. MacDonald qualify as "audit committee experts" for purposes of SEC rules and regulations.

We also have a conflicts committee composed of four members of the Board. The conflicts committee is available at the Board's discretion to review specific matters that the Board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to Seadrill Partners. The members of the conflicts committee may not be officers or employees of Seadrill Partners or directors, officers or employees of Seadrill or its affiliates, and must meet the independence standards established by the NYSE to serve on an audit committee of a board of directors and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to Seadrill Partners, approved by all of its members, and not a breach by its directors, Seadrill or its affiliates of any duties any of them may owe the Company or its unitholders. The current members of the conflicts committee are Mr. Horton, Mr. Cumming, Mr. Darlington and Mr. MacDonald.

In January 2020, the Board of Directors established a Compensation Committee among the members of the Board of Directors. The Compensation Committee comprises Mr. Cumming, Mr. MacDonald and Mr. Nelson. The Compensation Committee is responsible for establishing and reviewing the executive officer's compensation and benefits.

Management of OPCO

Our wholly owned subsidiary, Seadrill Operating GP LLC is the general partner of Seadrill Operating LP. We have the authority to appoint and elect the directors of Seadrill Operating GP LLC, who in turn appoint the officers of Seadrill Operating GP LLC. Certain of the officers of Seadrill Partners also serve as directors of Seadrill Operating GP LLC. The partnership agreement of Seadrill Operating LP provides that certain actions relating to Seadrill Operating LP must be approved by its board of directors. These actions include, among other things, establishing maintenance and replacement capital and other cash reserves and the determination of the amount of quarterly distributions by Seadrill Operating LP to its partners, including us. In addition, we own 51% of the limited liability company interests in Seadrill Capricorn Holdings LLC and control its operations and activities. We also own 100% of the limited liability company interests in Seadrill Partners Operating LLC and control its operations and activities. Please read Item 7 - "Major Unitholders and Related Party Transactions - Related Party Transactions - Operating Agreements for Seadrill Operating LP and Seadrill Capricorn Holdings LLC."

    D.     Employees

For the year ended December 31, 2020, our executive officers provided their services pursuant to the management and administrative services agreement.

The table below shows the number of employees contracted by Seadrill Partners and Seadrill for the year ended December 31, 2020.

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	Offshore	Onshore (1)
Employees
Contracted by Seadrill Partners	364	4
Contracted by Seadrill (2)	197	4
Total employees	561	8

(1) Staff served onshore in technical, commercial and administrative roles in various countries.

(2) Certain subsidiaries of Seadrill provide onshore advisory, operational and administrative support to our operating subsidiaries pursuant to service agreements. Please read Item 19 - "Exhibits" - "Advisory, Technical and Administrative Services Agreements", and "Management and Administrative Services Agreement".

Some of our contracted labor from Seadrill are represented by collective bargaining agreements. Some of these agreements require the contribution of certain amounts to retirement and pension funds. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. We consider our and Seadrill's relationships with the various unions as stable.

    E.     Unit Ownership

See Item 7 - "Major Unitholders and Related Party Transactions - Major Unitholders".

Item 7.         Major Unitholders and Related Party Transactions

    A.     Major Unitholders

The following table sets forth the beneficial ownership of units of Seadrill Partners LLC owned by beneficial owners of 5% or more of the units known by the company, and by its directors and executive officers as of March 31, 2021:

 

Name of Beneficial Owner	Common Units Beneficially Owned			Subordinated Units Beneficially Owned			Percentage of Total Common and Subordinated Units Beneficially Owned
	Number	Percent		Number	Percent
Seadrill Partners LLC Holdco Limited (1)	2,627,575	34.9	%	1,654,335	100.0	%	46.6	%
Anthony Horton (Director)	—	—	%	—	—	%	—	%
Andrew Cumming (Director)	—	—	%	—	—	%	—	%
John Darlington (Director)	—	—	%	—	—	%	—	%
John Roche (Director)	—	—	%	—	—	%	—	%
Keith MacDonald (Director)	*	*		—	—	%	*
Leif Nelson (Director)	*	*		—	—	%	*
Gunnar Winther Eliassen (Director)	—	—	%	—	—	%	—	%
Mo Meghji (Executive Officer)	—	—	%	—	—	%	—	%
Emma Li (Executive Officer)	—	—	%	—	—	%	—	%

 * Less than 1%.

(1) Seadrill Partners LLC Holdco Limited is an intermediate holding company which is ultimately owned by Seadrill Limited. Seadrill's principal shareholder is Hemen Holdings Limited. Hemen Holding Limited, a Cyprus Holding Company, and other related companies which are collectively referred to herein as Hemen, the shares of which are held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 27,193,826 shares, or 27.2%, of the common stock of Seadrill, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen.

Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders. However, if at any time any person or group owns beneficially more than 5% of any class of units then outstanding, any units beneficially owned by that person or group in excess of 5% may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes (except for purposes of nominating a person for election to the Board), determining the presence of a quorum or for other similar purposes under the Company's operating agreement, unless otherwise required by law. The voting rights of any such unitholders in excess of 5% will effectively be redistributed pro rata among the other common unitholders holding less than 5% of the voting power of all

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classes of units entitled to vote. The Seadrill Member, its affiliates and persons who acquired common units with the prior approval of the Board will not be subject to this 5% limitation except with respect to voting their common units in the election of the elected directors.

    B.     Related Party Transactions

From time to time, we have entered into agreements and consummated transactions with certain related parties. We may enter into related party transactions from time to time in the future. In connection with our IPO, we established a conflicts committee, comprised entirely of independent directors, which must approve all proposed material related party transactions.

Additional disclosure of related party transactions for the years ended December 31, 2020, 2019 and 2018 are presented in Note 19 - "Related party transactions" to the Consolidated Financial Statements included herein.

    C.     Interests of Experts and Counsel

Not applicable.

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Item 8.         Financial Information

    A.     Consolidated Statements and Other Financial Information

Please see Item 18 - "Financial Statements" below for additional information required to be disclosed under this item.

Legal Proceedings

Please see Note 22 - "Commitments and contingencies" to the Consolidated Financial Statements included herein.

The Company's Cash Distribution Policy

The Company does not currently make a distribution to its unitholders.

The ability of the Company to make a distribution to unitholders in the future will depend on both (i) the future operating results and financial position of the Company and (ii) future decisions made by the Board of Directors. There is no guarantee that unitholders will receive distributions in the future.

Any future distributions would be subject to certain restrictions. These restrictions include, but are not limited to, the following:

•Under Section 40 of the Marshall Islands Act, the Company may not make a distribution to the Company's unitholders if, after giving effect to the distribution, all liabilities of the Company, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specified property of the Company, exceed the fair value of the assets of the Company, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in the assets of the Company only to the extent that the fair value of that property exceeds that liability. Identical restrictions exist on the payment of distributions by OPCO to its equity holders.

•The Company's ability to make cash distributions will be limited by restrictions on distributions under its financing agreements. In addition, the Company's financing agreements contain material financial tests and covenants that must be satisfied in order to pay distributions.

•The Company will be required to make substantial capital expenditures to maintain its fleet. These expenditures may fluctuate significantly over time, particularly as drilling units near the end of their useful lives. In order to minimize these fluctuations, the Company is required to deduct estimated, as opposed to actual, maintenance and replacement capital expenditures from the amount of cash that the Company would otherwise have available for distribution to the Company's unitholders.

•The Company's ability to make distributions to unitholders depends on the performance of its controlled affiliates, including OPCO, and their ability to distribute cash to us. Our interests in OPCO represent the Company's only cash-generating assets. The ability of our controlled affiliates, including OPCO, to make distributions to the Company may be restricted by, among other things, the provisions of existing and future indebtedness, applicable limited partnership and limited liability company laws and other laws and regulations.

    B.     Significant Changes

There have been no significant changes since the date of our Consolidated Financial Statements included in this report, other than as described in Note 25 - "Subsequent events" thereto.

Item 9.        The Offer and Listing

    A.     Offer and Listing Details

Seadrill Partners LLC is a limited liability company that is traded over-the-counter on the OTC Pink Market under the ticker symbol "SDLPQ".

    B.     Plan of distribution

Not applicable.

    C.     Markets

Prior to December 23, 2019, our shares were listed on the NYSE. They are now traded over-the-counter under the trading symbol "SDLPQ".

    D.    Selling Shareholders

Not applicable.

    E.    Dilution

Not applicable.

    F.    Expenses of the issue

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Not applicable.

Item 10.         Additional Information

    A.     Share Capital

Not applicable.

    B.     Memorandum and Articles of Association

The information required to be disclosed under Item 10B is incorporated by reference to the Company's Registration Statement on Form 8-A filed with the SEC on October 17, 2012.

    C.     Material Contracts

Attached as exhibits to this annual report are the contracts we consider to be both material and not in the ordinary course of business. Other than these contracts, we have no material contracts other than those entered in the ordinary course of business. 

    D.     Exchange Controls

We are not aware of any governmental laws, decrees or regulations, including foreign exchange controls, in the Republic of The Marshall Islands that restrict the export or import of capital, or that affect the remittance of dividends, distributions, interest or other payments to non-resident and non-citizen holders of the Company's securities.

We are not aware of any limitations on the right of non-resident or foreign owners to hold or vote the Company's securities imposed by the laws of the Republic of The Marshall Islands or the Company's operating agreement.

    E.     Taxation

Taxation of the Company

Seadrill Partners LLC is organized as a limited liability company under the laws of the Republic of the Marshall Islands and is resident in the United Kingdom for taxation purposes by virtue of being centrally managed and controlled in the United Kingdom. Certain of our controlled affiliates are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. We intend that our business will be conducted and operated in a tax efficient manner. However, we cannot assure this result as tax laws in these or other jurisdictions may change, or we may enter into new business transactions, which could affect our tax liabilities.

Marshall Islands

Because Seadrill Partners LLC and its controlled affiliates do not carry on business or conduct transactions or operations in the Republic of the Marshall Islands, neither it nor its controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, and we do not expect this to change in the future, other than taxes or fees due to (i) the continued existence of legal entities registered in the Republic of the Marshall Islands, (ii) the incorporation or dissolution of legal entities registered in the Republic of the Marshall Islands, (iii) filing certificates (such as certificates of incumbency, merger, or redomiciliation) with the Marshall Islands registrar, (iv) obtaining certificates of goodstanding from, or certified copies of documents filed with, the Marshall Islands registrar or (v) compliance with Marshall Islands law concerning vessel ownership, such as tonnage tax. As a result, distributions OPCO receives from the controlled affiliates of Seadrill Partners LLC, and distributions Seadrill Partners LLC receives from OPCO, are not expected to be subject to Marshall Islands taxation.

United Kingdom

Seadrill Partners LLC is a resident of the United Kingdom for taxation purposes. Nonetheless, we expect that the distributions it receives from OPCO, generally will be exempt from taxation in the United Kingdom under applicable exemptions for distributions from subsidiaries. As a result, we do not expect to be subject to a material amount of taxation in the United Kingdom as a consequence of Seadrill Partners LLC being resident in the United Kingdom for taxation purposes.

United States

We have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to U.S. federal income tax to the extent that we earn income from U.S. sources or income that is treated as effectively connected with the conduct of a trade or business in the United States. We do not expect to earn a material amount of such taxable net income; however, we have controlled affiliates that conduct drilling operations in the U.S. Gulf of Mexico that are subject to taxation by the United States on their net income and may be required to withhold U.S. federal tax from distributions made to their owner. In March 2020, the U.S. enacted the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”), which grants taxpayers a five-year carry back period for net operating losses arising in tax years beginning after December 31, 2017 and before January 1, 2021. See Note 7 – "Taxation" to the Consolidated Financial Statements included herein for further details of the impact for 2020.

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Taxation of rig owning entities

A number of our drilling rigs are owned in tax-free jurisdictions such as Bermuda or the Cayman Islands. There is no taxation of the rig owners' income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income taxation of the rig owners' income, being Hungary and Luxembourg. There may also be income tax in certain other jurisdictions where rigs are owned by or allocated to local branches. Some of our rigs are subject to Swiss tax under a special finance regime through December 31, 2021, although we do not expect there to be a material effect on our Consolidated Financial Statements thereafter.

Please also see the section below entitled "Taxation in country of drilling operations".

Taxation in country of drilling operations

Income derived from drilling operations is generally taxed in the country where these operations take place. The taxation of income derived from drilling operations could be based on net income, deemed income, withholding taxes and or other bases, depending upon the applicable tax legislation in each country of operation. Some countries levy withholding taxes on bareboat charter payments (internal rig rent), branch profits, crew, dividends, interest and management fees.

Drilling operations can be carried out by locally incorporated companies, foreign branches of operating companies or foreign branches of the rig owning entities. We select the appropriate structure with due regard to the applicable legislation of each country where the drilling operation occur.

Taxation may also extend to the rig owning entity in some of the countries where the drilling operations are performed. Some countries have introduced new laws and rules since the commencement of certain drilling contracts, which may affect or have affected the position of the group, potentially leading to additional tax on rig owners. The group considers the applicability of these to individual companies and contracts based on the relevant facts and circumstances.

Net income

Net income corresponds to gross income derived from the drilling operations less tax-deductible costs (i.e. operating costs, crew, insurance, management fees and capital costs (internal bareboat fee; tax depreciation; interest costs) incurred in relation to those operations). In addition to net income tax, withholding tax on branch profits, dividends, internal bareboat fees, among other items, may also be levied.

Net income taxation for an international drilling contractor is complex, and pricing of internal transactions (e.g., rig sales; bareboat fees; services) will allocate overall taxable income between the relevant countries. We apply Organization for Economic Cooperation and Development, or "OECD", Transfer Pricing Guidelines as a basis to arrive at pricing for internal transactions. OECD Transfer Pricing Guidelines describe various methods to price internal services on terms believed by us to be no less favorable than are available from unaffiliated third parties. However, some tax authorities could disagree with our transfer pricing methods and disputes may arise in regards to correct pricing.

Deemed income

Deemed income tax is normally calculated based on gross turnover, which can include or exclude reimbursables and often reflects an assumed profit ratio, multiplied by the applicable corporate tax rate. Some countries will also levy withholding taxes on the distribution of dividend and/or branch profits at the deemed or other tax rate.

Withholding and other taxes

Some countries base their taxation solely on withholding tax on gross turnover. In addition, some countries levy stamp duties, training taxes or similar taxes on the gross turnover.

Customs duties

Customs duties are generally payable on the importation of drilling rigs, equipment, and spare parts into the country of operation, although several countries provide exemption from such duties for the temporary importation of drilling rigs. Such exemption may also apply to the temporary importation of equipment.

Taxation of other income

Other income related to crewing, management fees and technical services will generally be taxed in the country where the service provider is resident, although withholding tax and/or income tax may also be imposed in the country where the drilling operations take place.

Dividends and other investment income will be taxable in accordance with the legislation of the country where the company holding the investment is resident. For companies' resident in Bermuda, there is currently no tax on these types of income. Some countries levy withholding taxes on outbound dividends and interest payments.

Capital gains taxation

In respect of drilling rigs owned by companies in Bermuda, the Cayman Islands and Hungary, no capital gains tax is payable in these countries upon the sale or disposition of a rig. However, some countries may impose a capital gains tax or a claw-back of tax depreciation (on a full or partial basis) upon the sale of a rig during or attributable to such time as the rig is operating within such country, or within a certain time after completion of such drilling operations or when the rig is exported after completion of such drilling operations.

Other taxes

Our operations may be subject to sales taxes, value added taxes or other similar taxes in various countries.

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Material U.S. Federal Income Tax Considerations

The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders.

This discussion is based upon provisions of the Code, Treasury Regulations and current administrative rulings and court decisions, all as in effect or existence on the date of this prospectus and all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "we", "our" or "us" are references to Seadrill Partners LLC.

The following discussion applies only to beneficial owners of common units that own the common units as "capital assets" within the meaning of Section 1221 of the Code (i.e., generally, for investment purposes) and is not intended to be applicable to all categories of investors, such as unitholders subject to special tax rules (e.g., financial institutions, insurance companies, broker-dealers, tax-exempt organizations, retirement plans or individual retirement accounts or former citizens or long-term residents of the United States), persons who will hold the units as part of a straddle, hedge, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes, or persons that have a functional currency other than the U.S. Dollar, each of whom may be subject to tax rules that differ significantly from those summarized below. If a partnership or other entity classified as a partnership for U.S. federal income tax purposes holds the Company's common units, the tax treatment of its partners generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding the Company's common units, you should consult your own tax adviser regarding the tax consequences to you of the partnership's ownership of the Company's common units.

No ruling has been or will be requested from the IRS regarding any matter affecting the Company or prospective unitholders. The statements made herein may be challenged by the IRS and, if so challenged, may not be sustained upon review in a court.

This discussion does not contain information regarding any U.S. state or local, estate, gift or alternative minimum tax considerations concerning the ownership or disposition of common units. This discussion does not comment on all aspects of U.S. federal income taxation that may be important to particular unitholders in light of their individual circumstances, and each prospective unitholder is urged to consult its own tax adviser regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of common units.

Election to be Treated as a Corporation

The Company has elected to be treated as a corporation for U.S. federal income tax purposes. As a result, U.S. Holders (as defined below) will not be directly subject to U.S. federal income tax on the Company's income, but rather will be subject to U.S. federal income tax on distributions received from the Company and dispositions of units as described below.

U.S. Federal Income Taxation of U.S. Holders

As used herein, the term "U.S. Holder" means a beneficial owner of the Company's common units that owns (actually or constructively) less than 10% of the Company's equity and that is:

•an individual U.S. citizen or resident (as determined for U.S. federal income tax purposes);

•a corporation (or other entity that is classified as a corporation for U.S. federal income tax purposes) organized under the laws of the United States or any of its political subdivisions;

•an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

•a trust if (i) a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in effect to be treated as a U.S. person for U.S. federal income tax purposes.

Distributions

Subject to the discussion below of the rules applicable to PFICs, any distributions to a U.S. Holder made by the Company with respect to the Company's common units generally will constitute dividends, to the extent of the Company's current and accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of the Company's earnings and profits will be treated first as a non-taxable return of capital to the extent of the U.S. Holder's tax basis in its common units and, thereafter, as capital gain. U.S. Holders that are corporations generally will not be entitled to claim dividends received deductions with respect to distributions they receive from the Company because the Company is not a U.S. corporation. Dividends received with respect to the Company's common units generally will be treated as "passive category income" for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes.

Dividends received with respect to the Company's common units, by a U.S. Holder that is an individual, trust or estate (a "U.S. Individual Holder") may not be treated as "qualified dividend income", which is taxable to such U.S. Individual Holder at preferential tax rates as the Company's common units are not readily tradable on an established securities market in the United States as the Company's common units are no longer listed on the NYSE. Any dividends paid by us which are not treated as "qualified dividend income" will be taxed as ordinary income to a U.S. Individual Holder.

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Special rules may apply to any amounts received in respect of the Company's common units that are treated as "extraordinary dividends". In general, an extraordinary dividend is a dividend with respect to a common unit that is equal to or in excess of 10% of a unitholder's adjusted tax basis (or fair market value upon the unitholder's election) in such common unit. In addition, extraordinary dividends include dividends received within a one-year period that, in the aggregate, equal or exceed 20% of a unitholder's adjusted tax basis (or fair market value). If the Company pays an "extraordinary dividend" on the Company's common units that is treated as "qualified dividend income", then any loss recognized by a U.S. Individual Holder from the sale or exchange of such common units will be treated as long-term capital loss to the extent of the amount of such dividend.

Sale, Exchange, or Other Disposition of Common Units

Subject to the discussion of PFIC status below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of the Company's units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder's adjusted tax basis in such units. The U.S. Holder's initial tax basis in its units generally will be the U.S. Holder's purchase price for the units and that tax basis will be reduced (but not below zero) by the amount of any distributions on the units that are treated as non-taxable returns of capital (as discussed above under "Distributions"). Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder's holding period is greater than one year at the time of the sale, exchange or other disposition. Certain U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder's ability to deduct capital losses is subject to limitations. Such capital gain or loss generally will be treated as U.S. source income or loss, as applicable, for U.S. foreign tax credit purposes.

Medicare Tax on Net Investment Income

Certain U.S. Holders, including individuals, estates and trusts, will be subject to an additional 3.8% Medicare tax on, among other things, dividends and capital gains from the sale or other disposition of equity interests. For individuals, the additional Medicare tax applies to the lesser of (i) "net investment income" or (ii) the excess of "modified adjusted gross income" over $200,000 ($250,000 if married and filing jointly or $125,000 if married and filing separately). "Net investment income" generally equals the taxpayer's gross investment income reduced by deductions that are allocable to such income. Unitholders should consult their tax advisers regarding the implications of the additional Medicare tax resulting from their ownership and disposition of the Company's common units.

PFIC Status and Significant Tax Consequences

Adverse U.S. federal income tax rules apply to a U.S. Holder that owns an equity interest in a non-U.S. corporation that is classified as a PFIC for U.S. federal income tax purposes. In general, the Company will be treated as a PFIC with respect to a U.S. Holder if, for any taxable year in which the holder held the Company's units, either:

•at least 75% of the Company's gross income (including the gross income of the Company's drilling unit owning subsidiaries) for such taxable year consists of passive income (e.g., dividends, interest, capital gains from the sale or exchange of investment property and rents derived other than in the active conduct of a rental business); or

•at least 50% of the average value of the assets held by the Company (including the assets of the Company's drilling unit owning subsidiaries) during such taxable year produce, or are held for the production of, passive income.

Income earned, or treated as earned (for U.S. federal income tax purposes), by the Company in connection with the performance of services would not constitute passive income. By contrast, rental income generally would constitute "passive income" unless the Company was treated as deriving that rental income in the active conduct of a trade or business under the applicable rules.

Based on the Company's current and projected method of operation, the Company believes that the Company was not a PFIC for its 2020 taxable year, and the Company expects that it will not be treated as a PFIC for the current or any future taxable year. The Company expects that more than 25% of its gross income for its 2020 taxable year arose and for each future year will arise from such drilling contracts or other income that the Company believes should not constitute passive income, and more than 50% of the average value of the Company's assets for each such year will be held for the production of such non-passive income. Assuming the composition of the Company's income and assets is consistent with these expectations, the Company believes that it should not be a PFIC for its 2020 taxable year or any future year.

Distinguishing between arrangements treated as generating rental income and those treated as generating services income involves weighing and balancing competing factual considerations, and there is no legal authority under the PFIC rules addressing the Company's specific method of operation. Conclusions in this area therefore remain matters of interpretation. The Company is not seeking a ruling from the IRS on the treatment of income generated from the Company's drilling contracts or charters. Thus, it is possible that the IRS or a court could disagree with this position. In addition, although the Company intends to conduct its affairs in a manner to avoid being classified as a PFIC with respect to any taxable year, the Company cannot assure unitholders that the nature of its operations will not change in the future and that the Company will not become a PFIC in any future taxable year.

As discussed more fully below, if the Company was to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat the Company as a "Qualified Electing Fund", which the Company refers to as a "QEF election". As an alternative to making a QEF election, a U.S. Holder should be able to make a "mark-to-market" election with respect to the Company's common units, as discussed below. If the Company is a PFIC, a U.S. Holder will be subject to the PFIC rules described herein with respect to any of the Company's subsidiaries that are PFICs. However, the mark-to-market election discussed below will likely not be available with respect to shares of such PFIC subsidiaries. In addition, if a U.S. Holder owns the Company's common units during any taxable year that the Company is a PFIC, such holder must file an annual report with the IRS.

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Taxation of U.S. Holders Making a Timely QEF Election

If a U.S. Holder makes a timely QEF election (an "Electing Holder"), then, for U.S. federal income tax purposes, that holder must report as income for its taxable year its pro rata share of the Company's ordinary earnings and net capital gain, if any, for the Company's taxable years that end with or within the taxable year for which that holder is reporting, regardless of whether or not the Electing Holder received distributions from the Company in that year. The Electing Holder's adjusted tax basis in the common units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder's adjusted tax basis in common units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of the Company's common units. A U.S. Holder makes a QEF election with respect to any year that the Company is a PFIC by filing IRS Form 8621 with its U.S. federal income tax return. If contrary to the Company's expectations, the Company determines that the Company is treated as a PFIC for any taxable year, the Company will provide each U.S. Holder with the information necessary to make the QEF election described above.

Taxation of U.S. Holders Making a "Mark-to-Market" Election

If the Company was to be treated as a PFIC for any taxable year and, as the Company anticipates, the Company's units were treated as "marketable stock", then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a "mark-to-market" election with respect to the Company's common units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the U.S. Holder's common units at the end of the taxable year over the holder's adjusted tax basis in the common units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder's adjusted tax basis in the common units over the fair market value thereof at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder's tax basis in its common units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of the Company's common units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder's indirect interest in any of the Company's subsidiaries that were determined to be PFICs.

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election

If the Company was to be treated as a PFIC for any taxable year, a U.S. Holder that does not make either a QEF election or a "mark-to-market" election for that year (or a Non-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on the Company's common units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder's holding period for the common units), and (2) any gain realized on the sale, exchange or other disposition of the units. Under these special rules:

•the excess distribution or gain would be allocated ratably over the Non-Electing Holder's aggregate holding period for the common units;

•the amount allocated to the current taxable year and any taxable year prior to the taxable year the Company was first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income; and

•the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayers for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

These penalties would not apply to a qualified pension, profit sharing or other retirement trust or other tax-exempt organization that did not borrow money or otherwise utilize leverage in connection with its acquisition of the Company's common units. If the Company was treated as a PFIC for any taxable year and a Non-Electing Holder who is an individual dies while owning the Company's common units, such holder's successor generally would not receive a step-up in tax basis with respect to such units.

U.S. Federal Income Taxation of Non-U.S. Holders

A beneficial owner of the Company's common units (other than a partnership or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is referred to as a "Non-U.S. Holder". If you are a partner in a partnership (or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holding the Company's common units, you should consult your own tax adviser regarding the tax consequences to you of the partnership's ownership of the Company's common units.

Distributions

Distributions the Company pays to a Non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax if the Non-U.S. Holder is not engaged in a U.S. trade or business. If the Non-U.S. Holder is engaged in a U.S. trade or business, the Company's distributions will be subject to U.S. federal income tax to the extent they constitute income effectively connected with the Non-U.S. Holder's U.S. trade or business. However, distributions paid to a Non-U.S. Holder that is engaged in a U.S. trade or business may be exempt from taxation under an income tax treaty if the income arising from the distribution is not attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder.

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Disposition of Units

In general, a Non-U.S. Holder is not subject to U.S. federal income tax or withholding tax on any gain resulting from the disposition of the Company's common units provided the Non-U.S. Holder is not engaged in a U.S. trade or business. A Non-U.S. Holder that is engaged in a U.S. trade or business will be subject to U.S. federal income tax in the event the gain from the disposition of units is effectively connected with the conduct of such U.S. trade or business (provided, in the case of a Non-U.S. Holder entitled to the benefits of an income tax treaty with the United States, such gain also is attributable to a U.S. permanent establishment). However, even if not engaged in a U.S. trade or business, individual Non-U.S. Holders may be subject to tax on gain resulting from the disposition of the Company's common units if they are present in the United States for 183 days or more during the taxable year in which those units are disposed and meet certain other requirements.

Backup Withholding and Information Reporting

In general, payments to a non-corporate U.S. Holder of distributions or the proceeds of a disposition of common units is subject to information reporting. These payments to a non-corporate U.S. Holder also may be subject to backup withholding if the non-corporate U.S. Holder:

•fails to provide an accurate taxpayer identification number;

•is notified by the IRS that it has failed to report all interest or corporate distributions required to be reported on its U.S. federal income tax returns; or

•in certain circumstances, fails to comply with applicable certification requirements.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on IRS Form W-8BEN, W-8BEN-E, W-8ECI or W-8IMY, as applicable.

Backup withholding is not an additional tax. Rather, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by timely filing a U.S. federal income tax return with the IRS.

In addition, individual citizens or residents of the United States holding certain "foreign financial assets" (which generally includes stock and other securities issued by a foreign person unless held in an account maintained by a financial institution) that exceed certain thresholds (the lowest being holding foreign financial assets with an aggregate value in excess of: (1) $50,000 on the last day of the tax year or (2) $75,000 at any time during the tax year) are required to report information relating to such assets. Significant penalties may apply for failure to satisfy the reporting obligations described above. Unitholders should consult their tax advisers regarding the reporting obligations, if any, that result from their purchase, ownership or disposition of the Company's units.

Non-United States Tax Considerations

Unless the context otherwise requires, references in this section to "we", "our" or "us" are references to Seadrill Partners LLC.

Marshall Islands Tax Consequences

The following discussion is based upon the current laws of the Republic of the Marshall Islands applicable to persons who are not citizens of and do not reside in, maintain offices in or carry on business or conduct transactions or operations in the Republic of the Marshall Islands.

Because the Company and the Company's subsidiaries (including those resident there) do not and do not expect to carry on business or conduct transactions or operations in the Republic of the Marshall Islands, under current Marshall Islands law the Company's unitholders will not be subject to Marshall Islands taxation or withholding on distributions, including upon distribution treated as a return of capital, the Company makes to the Company's unitholders. In addition, the Company's unitholders will not be subject to Marshall Islands stamp, capital gains or other taxes on the purchase, ownership or disposition of common units and will not be required by the Republic of the Marshall Islands to file a tax return relating to their ownership of common units.

United Kingdom Tax Consequences

The following is a discussion of the material U.K. tax consequences that may be relevant to unitholders who are persons not resident for tax purposes in the United Kingdom (and who are persons who have not been resident for tax purposes in the United Kingdom) ("non-U.K. Holders").

Unitholders who are, or have been, resident in the United Kingdom are urged to consult their own tax advisers regarding the potential U.K. tax consequences to them of an investment in the Company's common units. For this purpose, a company incorporated outside of the U.K. will be treated as resident in the United Kingdom in the event its central management and control is carried out in the United Kingdom.

The discussion that follows is based upon existing U.K. legislation and current H.M. Revenue & Customs practice as of April 30, 2021, both of which may change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences of unit ownership described below.

The Company is not required to withhold U.K. tax when paying distributions to unitholders.

Under U.K. taxation legislation, non-U.K. Holders will not be subject to tax in the United Kingdom on income or profits, including chargeable (capital) gains, in respect of the acquisition, holding, disposition or redemption of the common units, provided that:

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•such holders do not use or hold and are not deemed or considered to use or hold their common units in the course of carrying on a trade, profession or vocation in the United Kingdom; and

•such holders do not have a branch or agency or permanent establishment in the United Kingdom through which such common units are used, held or acquired.

U.K. stamp duty should not be payable in connection with a transfer of units, provided that the instrument of transfer is executed and retained outside the U.K. and no other action is taken in the U.K in relation to the transfer.

No U.K. stamp duty reserve tax will be payable in respect of any agreement to transfer units provided that the units are not registered in a register kept in the U.K. by or on behalf of the Company. The Company currently does not intend that any such register will be maintained in the U.K.

Each prospective unitholder is urged to consult their own tax counsel or other adviser with regard to the legal and tax consequences of unit ownership under their particular circumstances.

    F.     Dividends and Paying Agents

Not applicable.

    G.    Statements by Experts

Not applicable.

    H.     Documents on Display

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). In accordance with these requirements we file reports and other information with the Commission. These materials, including this annual report and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, NE, Room 1580, Washington, D.C. 20549.  You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C. The Commission maintains a website (http://www.sec.gov.) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. In addition, documents referred to in this annual report may be inspected at our principal executive offices at Building 11, Chiswick Park, 566 Chiswick High Road, London, W4 5YS, United Kingdom.

    I.    Subsidiary Information

Not applicable.

Item 11.        Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. The Company may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.

Due to the filing of the Bankruptcy Petitions, interest is no longer incurred on our debt facilities. Prior to filing for Chapter 11, we entered into a derivative agreement to mitigate the risk of interest rate fluctuations. We defaulted on payments due on the interest rate swaps on November 23, 2020 in preparation for the Chapter 11 filing.

As a result, our counterparties terminated all outstanding transactions governed by the International Swaps and Derivatives Association, Inc. ("ISDA"). The derivative transactions are recognized at the recoverable amount under the ISDA's as agreed with our lenders. As at December 31, 2020 we had $20.8 million in estimated derivative instrument settlements payable, reflected as "liabilities subject to compromise" in our Consolidated Balance Sheet.

Interest rate risk management

Our exposure to interest rate risk relates mainly to our floating interest rate debt and balances of surplus funds placed with financial institutions. The exposure related to our floating interest debt has reduced since filing for Chapter 11 as interest is no longer incurred on our debt facilities. Our objective is to obtain the most favorable interest rate borrowings available without increasing its exposure to fluctuating interest rates. Surplus funds are used to repay revolving credit tranches or placed in accounts and deposits with reputable financial institutions in order to maximize returns, while providing us with flexibility to meet all requirements for working capital and capital investments. The extent to which we utilize interest rate swaps to manage our interest rate risk is determined by our net debt exposure and our views on future interest rates.

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Interest rate swap agreements

As at November 23, 2020, we had interest rate swaps for a combined outstanding principal amount of $2,714.1 million, (December 31, 2019: $2,735.8 million) swapping floating rate for an average fixed rate of 2.49% per annum. The fair value of the interest rate swaps outstanding as of December 31, 2020 was a liability of $20.8 million (December 31, 2019: liability of $17.7 million). The collateral vessels under our TLB have been pledged as collateral against our interest rate swap liabilities. The interest rate swaps are secured on a pari passu basis with the TLB lenders. The swap providers rank lower on the payment waterfall with regards to the super senior loans.

We record interest rate swaps on a net basis where netting is as allowed under ISDA Master Agreements. We classify the net asset or liability within other current assets or current liabilities. We have not designated any interest swaps as hedges and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statements of Operations included herein under "(Loss)/gain on derivative financial instruments".

On December 1, 2020, our interest rate swaps were terminated under the ISDA and an adjustment for credit risk on the interest rate swap position was reversed to "other financial expenses" in the Consolidated Statement of Operations included herein, totaling $7.1 million. The residual liability represents the counterparty claimed value of $20.8 million, which was reclassified to "liabilities subject to compromise" in the Consolidated Balance Sheet, included herein, as at December 31, 2020.

The total realized and unrealized loss recognized under "loss/gain on derivative financial instruments" in the Consolidated Statements of Operations, included herein, relating to interest rate swap agreements for 2020 was a loss of $16.1 million (2019: loss of $27.7 million, 2018: gain of $24.9 million).

Our interest rate swap agreements as of November 23, 2020, were as follows:

Maturity date	Outstanding principal as at November 23, 2020	Receive rate	Pay rate
	(In $ millions)
February 21, 2021	2,714.1	3 month LIBOR	2.45% to 2.52%	(1) (2)
Total outstanding principal	2,714.1

(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.

(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.

Following the defaults on our debt and the termination of our derivatives we no longer have any net exposure to short term fluctuations in interest rates.

As of December 31, 2019, $156.3 million of our debt was exposed to interest rate fluctuations. An increase or decrease in short-term interest rates of 100 basis points would thus increase or decrease, respectively, our interest expense by approximately $1.5 million on an annual basis as of December 31, 2019.

The credit exposure of interest rate swap agreements is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements, adjusted for counterparty non-performance credit risk assumptions. It is our policy to enter into ISDA Master Agreements, with the counterparties to derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes us.

Foreign currency risk

Our cash and cash equivalents are held primarily in U.S. Dollars with minor balances held in other currencies. Our revenue and costs are primarily denominated in U.S. Dollars although a proportion of our vessel and rig operating expenses and a small amount of revenue are denominated in other currencies. The main currencies in which we have foreign currency exposures are, Canadian Dollars, Thai Baht, Nigerian Naira and Malaysian Ringgit. There is a risk that currency fluctuations could have an adverse effect on the value of the Company's cash flows, but this would not be a material impact on our results.

Our foreign currency risk arises from:

•the measurement of monetary assets and liabilities denominated in foreign currencies converted to U.S. Dollars, with the resulting gain or loss recorded as "currency exchange loss/gain" in the Consolidated Statements of Operations; and

•the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies.

We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.

Credit risk

We have financial assets which expose us to credit risk arising from possible default by a counterparty. Our counterparties primarily include our customers, which are international oil companies, national oil companies or large independent companies or financial institutions. We consider these counterparties to be creditworthy and do not expect any significant loss due to credit risk. We don't demand collateral from our counterparties in the normal course of business. Credit risk is also considered as part of our expected credit loss provision. Refer to Note 2 - "Accounting Policies" to the Consolidated Financial Statements included herein for further information on our methodology for recognizing expected credit losses related to our credit risk.

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Concentration of Credit Risk

There is a concentration of credit risk with respect to revenue as one of our customers represent more than 10% of total revenues. Refer to Note 5 - "Segment information" to the Consolidated Financial Statements included herein for an analysis of our revenue by customer. The market for our services is the offshore oil and gas industry, and our customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral from them. Reserves for potential credit losses are maintained when necessary.

There is a concentration of credit risk with respect to cash and cash equivalents as most of the amounts are deposited with Danske Bank A/S and Citibank N.A. We consider these risks to be remote given the strong credit rating of these banks.

Item 12.     Description of Securities Other than Equity Securities

Not applicable.

    A.     Debt securities

Not applicable.

    B.     Warrants and rights

Not applicable.

    C.     Other securities

Not applicable.

    D.     American Depositary shares

Not applicable.

PART II

Item 13.     Defaults, Dividend Arrearages and Delinquencies

The Debtors filing of Bankruptcy on the petition date constituted an event of default under our secured credit facilities and unsecured bond facilities and were reported as "Liabilities subject to compromise" on the Consolidated Balance Sheets at December 31, 2020.

Item 14.         Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

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Item 15.     Controls and Procedures

a)    Disclosure Controls and Procedures

Management assessed the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 and Rule 15d-15 of the Exchange Act as of December 31, 2020. Based upon that evaluation, the Principal Executive Officer and the Principal Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the evaluation date.

b)    Management's Annual Report on Internal Controls over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) promulgated under the Exchange Act.

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Board, management and other personnel, 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 and includes those policies and procedures that:

•Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•Provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and

•Provide reasonable assurance regarding the 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 or compliance with the policies or procedures may deteriorate.

Our Management, with the participation of the Chief Executive Officer, whom is also the Chief Financial Officer, assessed the effectiveness of the design and operation of our internal control over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2020.

Management conducted the evaluation of the effectiveness of internal control over financial reporting based on the Internal Control- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors. On the basis of this evaluation, Management concluded that, as of December 31, 2020, the Company's internal control over financial reporting was effective.

c)     Changes in Internal Control over Financial Reporting

There were no changes in these internal controls during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 16A.     Audit Committee Financial Expert

The Board has determined that John Darlington and Keith MacDonald qualify as audit committee financial experts and are independent under applicable NYSE and SEC standards. See Item 6A - "Directors and Senior Management" for a description of their relevant experience.

Item 16B.     Code of Ethics

We have adopted a Code of Ethics that applies to all entities controlled by the Company and its employees, directors, officers and agents of the Company. We will provide any person, free of charge, a copy of the Code of Ethics upon written request to our registered office.

Item 16C.     Principal Accountant Fees and Services

Our principal accountant for the fiscal years ended December 31, 2020 and December 31, 2019 was PricewaterhouseCoopers LLP in the United Kingdom.

Fees Incurred by the Company for PricewaterhouseCoopers LLP's Services

The following table sets forth the fees related to audit and other services provided by the principal accountants and their affiliates:

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(In $ millions)	2020	2019
Audit Fees	1,499,222	1,498,268
Audit-Related Fees	—	—
Tax Fees	—	—
All other fees	9,629	8,634
	1,508,851	1,506,902

Audit Fees

Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.

Audit-Related Fees

Not applicable.

Tax Fees

Not applicable.

All Other Fees

All other fees include services other than audit fees, audit-related fees and taxation fees set forth above, primarily including assistance in the preparation of financial statements for subsidiaries.

Audit committee approvals

The audit committee has the authority to pre-approve permissible audit-related and non-audit services not prohibited by law to be performed by our independent auditors and associated fees. Engagements for proposed services either may be separately pre-approved by the audit committee or entered into pursuant to detailed pre-approval policies and procedures established by the audit committee, as long as the audit committee is informed on a timely basis of any engagement entered into on that basis. The audit committee separately pre-approved all engagements and fees paid to our principal accountant for all periods in 2020.

Item 16D.     Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E.     Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not applicable.

Item 16F.     Change in Registrant's Certifying Accountant

Not applicable.

72

Table of Contents

Item 16G.     Corporate Governance

Overview

Although since December 2019, the Company was delisted from the NYSE, we believe that our established practices in the area of corporate governance are in line with the spirit of the NYSE standards and provide adequate protection to the Company's unitholders. As an NYSE listed foreign private issuer, we were not required to comply with the corporate governance practices followed by U.S. companies under the NYSE listing standards, but we were required to state any significant differences between our governance practices and the practices required by the NYSE for U.S. companies. The significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies are set forth below.

Independence of Directors

The NYSE rules do not require a listed company that is a foreign private issuer to have a board of directors that is composed of a majority of independent directors. Under Marshall Islands law, we are not required to have a board of directors composed of a majority of directors meeting the independence standards described in NYSE rules. However, the Board has determined that each of Mr. Darlington, Mr. Horton, Mr. Cumming and Mr. MacDonald satisfies the independence standards established by the NYSE, as applicable to us.

Executive Sessions

The NYSE requires that non-management directors of a listed U.S. company meet regularly in executive sessions without management. The NYSE also requires that all independent directors of a listed U.S. company meet in an executive session at least once a year. As permitted under Marshall Islands law and the Company's limited liability company agreement, our non-management directors do not regularly hold executive sessions without management and we do not expect them to do so in the future.

Nominating/Corporate Governance Committee

The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Marshall Islands law and the Company's limited liability company agreement, we do not currently have a nominating or corporate governance committee.

Compensation Committee

The NYSE requires that a listed U.S. company have a compensation committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. In January 2020, the Board of Directors established a Compensation Committee among the members of the Board of Directors. Prior to this date, and as permitted under Marshall Islands law and the Company's limited liability company agreement, we did not have a compensation committee.

Corporate Governance Guidelines

The NYSE requires listed U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Marshall Islands law and we have not adopted such guidelines.

Issuance of Additional Units

The NYSE requires that a listed U.S. company obtain unitholder approval in certain circumstances prior to the issuance of additional units. Consistent with Marshall Islands law and the Company's operating agreement, the Company is authorized to issue an unlimited amount of additional limited liability company interests and options, rights and warrants to buy limited liability company interests for the consideration and on the terms and conditions determined by the Board of Directors without the approval of the unitholders.

Item 16H.     Mine Safety Disclosure

Not applicable.

PART III

Item 17.     Financial Statements

See Item 18 - "Financial Statements" below.

Item 18.     Financial Statements

The following financial statements listed below and set forth beginning on Page F-1 together with the related report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm, are filed as part of this annual report:

73

Item 19.     Exhibits

The following exhibits are filed as part of this annual report:

Exhibit Number	Description
1.1	Certificate of Formation of Seadrill Partners LLC (incorporated by reference to Exhibit 3.1 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on September 21, 2012)
1.2	First Amended and Restated Operating Agreement of Seadrill Partners LLC, dated October 24, 2012, (incorporated by reference to Exhibit 1.2 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
1.2.1	Amendment No. 1 to the First Amended and Restated Operating Agreement of Seadrill Partners LLC, dated February 23, 2014 (incorporated by reference to Exhibit 1.2.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
1.2.2	Amendment No. 2 to the First Amended and Restated Operating Agreement of Seadrill Partners LLC, dated May 22, 2019 (incorporated by reference to Exhibit 1.2.2 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2019 filed on June 15, 2020).
1.3	Amended and Restated Agreement of Limited Partnership of Seadrill Operating LP dated July 21, 2014 (incorporated by reference to Exhibit 10.2 of the registrants Current Report on Form 6-K, filed on July 21, 2014)
1.4	Limited Liability Company Agreement of Seadrill Operating GP LLC, dated September 27, 2012 (incorporated by reference to Exhibit 1.4 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
1.5	Amended & Restated Limited Liability Company Agreement of Seadrill Capricorn Holdings LLC dated October 18, 2012 (incorporated by reference to Exhibit 1.5 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.1.	Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of October 22, 2012 (incorporated by reference to Exhibit 4.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.1.1	Amendment No. 1 to Contribution and Sale Agreement among Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating GP LLC, Seadrill Operating LP, Seadrill Capricorn Holdings LLC, Seadrill Opco Sub LLC, Seadrill Americas Inc., Seadrill Offshore AS, and Seadrill UK Ltd., dated as of June 30, 2013 (incorporated by reference to the Exhibit 10.1 of the registrant's Report on Form 6-K for the six month period ended June 30, 2013, filed on September 30, 2013)
4.2	Omnibus Agreement among Seadrill Limited, Seadrill Partners LLC, Seadrill Member LLC, Seadrill Operating LP, Seadrill Operating GP LLC, and Seadrill Capricorn, dated as of October 24, 2012 (incorporated by reference to Exhibit 4.2 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.3	Novation and Amendment Agreement in respect of the Management and Administrative Services Agreement among Seadrill Management AS, Seadrill Management Ltd and Seadrill Partners LLC, dated October 24 2012, as amended April 28, 2016 (incorporated by reference to Exhibit 4.3 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016).
4.4	Advisory, Technical and Administrative Services Agreement with Seadrill Americas, Inc. (incorporated by reference to Exhibit 4.4 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2012, filed on April 30, 2013)
4.5	Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Vencedor Ltd. dated January 1, 2012 (incorporated by reference to Exhibit 10.5.1 of Amendment No. 3 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.6	Advisory, Technical and Administrative Services Agreement between Seadrill Management AME Ltd and Seadrill Deepwater Drillship Ltd. dated January 1, 2012 (incorporated by reference to Exhibit 10.5.2 of Amendment No. 3 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.7	Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC (incorporated by reference to the Exhibit 10.4 of the registrant's Report on Form 6-K, filed on March 11, 2014)
4.8	Administrative, Technical and Advisory Agreement, effective as of January 1, 2012 by and among Seadrill Management AME Ltd. and Seadrill Ghana Operations Ltd., effective as of December 13, 2013, by and among Seadrill Americas Inc. and Seadrill Gulf Operations Sirius LLC (incorporated by reference to Exhibit 10.5 of the registrant's Report on Form 6-K, filed on March 11, 2014)
4.9	Administrative, Technical and Advisory Agreement, effective as of March 21, 2014 between Seadrill Americas Inc. and Seadrill Gulf Operations Auriga LLC. (incorporated by reference to Exhibit 4.7.5 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2013, filed on April 30, 2014).
4.10	Administrative, Technical and Advisory Agreement, effective as of February 15, 2013, between Seadrill Americas Inc. and Seadrill Gulf Operations Vela LLC (incorporated by reference to Exhibit 4.7.6 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015).
4.11	Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Nigeria Operations Limited. (incorporated by reference to the Exhibit 10.1 of the registrant's Report on Form 6-K for the six month period ended June 30, 2015, filed on October 5, 2015)
4.12	Administrative Support Contract, dated July 1, 2014, between Seadrill Mobile Units Nigeria Limited and Seadrill Offshore Nigeria Limited. (incorporated by reference to the Exhibit 10.2 of the registrant's Report on Form 6-K for the six month period ended June 30, 2015, filed on October 5, 2015)
4.13	Advisory, Technical and Administrative Services Agreement, dated June 19, 2015, between Seadrill Management AME Ltd. and Seadrill Polaris Ltd. (incorporated by reference to the Exhibit 10.4 of the registrant's Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.14	Amended and Restated Revolving Loan Agreement, dated August 31, 2013, among Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, as borrowers, and Seadrill Limited, as lender (incorporated by reference to the Exhibit 10.1 of the registrant's Report on Form 6-K for the six month period ended June 30, 2013, filed on September 30, 2013)
4.14.1	Second Amendment to Revolving Loan Agreement, dated March 1, 2014, among Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC, as borrowers, and Seadrill Limited, as lender (incorporated by reference to Exhibit 4.8.3 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2013, filed on April 30, 2014)
4.15	Loan Agreement dated September 28, 2012 between Seadrill Limited and Seadrill Vencedor Ltd. (incorporated by reference to Exhibit 10.15 of Amendment No. 1 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on October 5, 2012)

74

Exhibit Number	Description
4.15.1	Amendment to the Loan Agreement between Seadrill Limited and Seadrill Vencedor Limited dated August 28, 2014 (incorporated by reference to Exhibit 4.42 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.15.2	Amendment to the Loan Agreement between Seadrill Limited and Seadrill Vencedor Limited dated April 14, 2015(incorporated by reference to Exhibit 4.43 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.16	US$440,000,000 Secured Credit Facility Agreement dated December 4, 2012 between Seadrill Limited, as borrower, the subsidiaries of Seadrill Limited named therein as guarantors, and the banks and financial institutions named therein as lenders (incorporated by reference to the Exhibit 10.2 of the registrant's Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.16.1	Letter Agreement regarding the US$440,000,000 Secured Credit Facility Agreement, dated June 18, 2015 (incorporated by reference to Exhibit 4.17.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.16.2	Waiver Approval Letter regarding the US$440,000,000 Secured Credit Facility Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.17.2 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.16.3	Consent Request and Waiver Approval Letter regarding the US$440,000,000 Secured Credit Facility Agreement, dated March 28, 2017
4.17	Loan Agreement, dated May 16, 2013, between Seadrill Limited, Seadrill T-15 Ltd., Seadrill Partners Operating LLC and Seadrill International Limited (incorporated by reference to the Exhibit 10.3 of the registrant's Report on Form 6-K for the six months ended June 30, 2013, filed on September 30, 2013)
4.18	Loan Agreement, dated October 11, 2013, by and among Seadrill Limited, Seadrill T-16 Ltd. and Seadrill Partners Operating LLC (incorporated by reference to Exhibit 10.6 of the registrant's Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.19	Amended and Restated Credit Agreement dated as of June 26, 2014, among Seadrill Operating LP, Seadrill Partners Finco LLC, Seadrill Capricorn Holdings LLC, various lenders and Deutsche Bank AG New York Branch, as Administrative Agent and Collateral Agent (incorporated by reference to the Exhibit 10.1 of the registrant's Report on Form 6-K, filed on June 30, 2014)
4.20	Second Amended and Restated Agreement dated November 4, 2014, among Seadrill Tellus Ltd. and Seadrill Vela Hungary Kft., as Borrowers, Seadrill Limited, as Parent, the guarantors party thereto, ING Bank N.V., as Agent, the lenders party thereto and the other parties thereto, relating to the US$1,450,000,000 Senior Secured Credit Facility Agreement, originally dated March 20, 2013 (incorporated by reference to Exhibit 4.40 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.20.1	Letter Agreement regarding the Second Amended and Restated Agreement, dated May 28, 2015 (incorporated by reference to Exhibit 4.22.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.20.2	Waiver Approval Letter regarding the Second Amended and Restated Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.22.2 of the registrant’s Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.20.3	Consent Request and Waiver Approval Letter regarding the Amended and Restated Agreement, dated March 28, 2017
4.21	On Demand and Guarantee and Indemnity, dated November 4, 2014, between Seadrill Partners LLC and ING Bank N.V. (incorporated by reference to Exhibit 4.41 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.22	Amendment and Restatement Agreement, dated June 19, 2015, between Seadrill Polaris Ltd. as borrower, Seadrill Limited as parent, Ship Finance International Limited as retiring guarantor and the other companies listed therein as guarantors, the banks and financial institutions listed therein as lenders, DNB Bank ASA and Nordea Bank AB, London Branch as bookrunners, the banks and financial institutions named therein as mandated lead arrangers and DNB Bank ASA, as agent, relating to the US$420,000,000 Term Loan and Revolving Credit Facilities Agreement, originally dated December 28, 2012, as previously amended (incorporated by reference to the Exhibit 10.5 of the registrant's Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.22.1	Waiver Approval Letter regarding the Amendment and Restatement Agreement, dated April 28, 2016 (incorporated by reference to Exhibit 4.24.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.22.2	Consent Request and Waiver Approval Letter regarding the Second Amendment and Restatement Agreement, dated March 29, 2017
4.23	Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Hungary Kft and Seadrill Limited (incorporated by reference to Exhibit 4.25 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.24	Loan Agreement, dated April 28, 2016, but effective as of December 17, 2015, between Seadrill Neptune Hungary Kft and Seadrill Gulf Operations Sirius LLC (incorporated by reference to Exhibit 4.26 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2015, filed on April 28, 2016)
4.25	Bareboat Charter Agreement between Seadrill Offshore AS and Seadrill Canada Ltd. dated October 5, 2012 (incorporated by reference to Exhibit 10.16 of Amendment No. 3 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.26	Bareboat Charter Agreements between Seadrill China Operations Ltd. and Seadrill Offshore AS dated October 5, 2012 (incorporated by reference to Exhibit 10.17 of Amendment No. 3 to the registrant's Registration Statement on Form F-1 (File No. 333-184023), filed on October 17, 2012)
4.27	Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-15 Ltd. and Seadrill UK Ltd. (incorporated by reference to Exhibit 10.1 of Amendment No. 3 to the registrant's Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.28	Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill T-16 Ltd. and Seadrill UK Ltd. (incorporated by reference to Exhibit 10.2 of the registrant's Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.29	Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-15 (incorporated by reference to Exhibit 10.3 of the registrant's Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.30	Rig Rental Agreement, effective as of December 10, 2012, by and among Seadrill International Ltd. and Seadrill UK Ltd., relating to the T-16 (incorporated by reference to Exhibit 10.2 of the registrant's Registration Statement on Form F-3 (File No. 333-192053), filed on November 1, 2013)
4.31	Contribution, Purchase and Sale Agreement, dated March 11, 2014 (incorporated by reference to the Exhibit 10.2 of the registrant's Report on Form 6-K, filed on March 17, 2014)
4.32	Limited Partner Interest Purchase Agreement, dated as of July 17, 2014, between Seadrill Limited and Seadrill Partners LLC (incorporated by reference to Exhibit 10.1 of the registrant's Report on Form 6-K, filed on July 21, 2014.
4.33	Contribution, Purchase and Sale Agreement, dated November 4, 2014, by and among Seadrill Limited, Seadrill Partners LLC, Seadrill Capricorn Holdings LLC and Seadrill Americas Inc. (incorporated by reference to Exhibit 4.39 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2014, filed on April 21, 2015)
4.34	Purchase and Sale Agreement, dated as of June 16, 2015, by and among Seadrill Limited, Seadrill Operating LP, Seadrill Polaris Ltd. (incorporated by reference to the Exhibit 10.1 of the registrant's Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)

75

Exhibit Number	Description
4.35	Promissory Note, dated as of June 19, 2015, between Seadrill Operating LP and Seadrill Limited (incorporated by reference to the Exhibit 10.2 of the registrant's Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.36	Guaranty, dated as of June 19, 2015, between Seadrill Partners LLC as the guarantor and Seadrill Limited as the holder (incorporated by reference to the Exhibit 10.3 of the registrant's Report on Form 6-K for the three month period ended March 31, 2015, filed on July 2, 2015)
4.37	Fifth Amendment and Restated Agreement, dated 16 August 2017, relating to the USD 420,000,000 Term Loan and Revolving Credit Facilities Agreement of Seadrill Polaris Ltd, as borrower (incorporated by reference to the Exhibit 10.1 of the registrants Report on Form 6-K, filed August 17, 2017).
4.37.1	Amendment to USD 420,000,000 Term Loan and Revolving Credit Facilities Agreement of Seadrill Polaris Ltd, as borrower, dated August 29, 2019 ((incorporated by reference to Exhibit 4.37.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2019 filed on June 15, 2020).
4.38	Third Amendment and Restated Agreement, dated 16 August 2017, relating to, among other things, the USD 483,333,333.34 Third Amended and Restated Senior Secured Credit Facility Agreement for Seadrill Vela Hungary Kft., as borrower (incorporated by reference to the Exhibit 10.2 of the registrants Report on Form 6-K, filed August 17, 2017).
4.38.1	Amendment to US 483,333,333.34 Secured Credit Facilities Agreement of Seadrill Vela Hungary Kft, as borrower, dated August 29, 2019 (incorporated by reference to Exhibit 4.38.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2019 filed on June 15, 2020).
4.39	China ECA Facility Framework Agreement, dated 16 August 2017, relating to, among other things, a new USD 119,100,000 Secured Credit Facility Agreement of Seadrill T-15 Ltd. and Seadrill T-16 Ltd., each as borrowers (incorporated by reference to the Exhibit 10.3 of the registrants Report on Form 6-K, filed August 17, 2017).
4.39.1	Amendment to US 119,100,000 Secured Credit Facilities Agreement of Seadrill T-15 Ltd. and Seadrill T-16 Ltd., each as borrowers, dated August 29, 2019 (incorporated by reference to Exhibit 4.39.1 of the registrant's Annual Report on Form 20-F for the year ended December 31, 2019 filed on June 15, 2020).
4.40	Consent & Amendment No. 1, dated February 12, 2018, relating to the Term Loan B Credit Agreement (incorporated by reference to the Exhibit 10.1 of the registrants Report on Form 6-K, filed February 13, 2018).
7.1	Amended and Restated Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Partners LLC, dated September 11 2017 (incorporated by reference to the Exhibit 14.1 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.2	Management and Administrative Services Agreement between Seadrill Management Ltd and Seabras Rig Holdco Kft, dated September 11 2017 (incorporated by reference to the Exhibit 14.2 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.3	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Auriga Hungary Kft, dated September 11 2017 (incorporated by reference to the Exhibit 14.3 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.4	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Canada Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.4 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.5	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill China Operations Ltd S.à .r.l, dated September 11 2017 (incorporated by reference to the Exhibit 14.5 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.6	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Deepwater Drillship Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.6 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.7	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Far East Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.7 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.8	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Ghana Operations Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.8 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.9	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Auriga LLC, dated September 11 2017 (incorporated by reference to the Exhibit 14.9 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.10	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Gulf Operations Vela LLC, dated September 11 2017 (incorporated by reference to the Exhibit 14.10 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.11	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Hungary Kft, dated September 11 2017 (incorporated by reference to the Exhibit 14.11 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.12	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill International Limited, dated September 11 2017 (incorporated by reference to the Exhibit 14.12 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.13	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Leo Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.13 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).

76

Exhibit Number	Description
7.14	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Polaris Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.14 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.15	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill T-15 Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.15 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.16	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill T-16 Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.16 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.17	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill US Gulf LLC, dated September 11 2017 (incorporated by reference to the Exhibit 14.17 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.18	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vela Hungary Kft, dated September 11 2017 (incorporated by reference to the Exhibit 14.18 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
7.19	Management and Administrative Services Agreement between Seadrill Management Ltd and Seadrill Vencedor Ltd, dated September 11 2017 (incorporated by reference to the Exhibit 14.19 of the registrants Annual Report on Form 20-F for the year ended December 31, 2017, filed April 12, 2018).
8.1*	List of Subsidiaries of Seadrill Partners LLC
12.1*	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
13.1*	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1*	Consent of Independent Registered Public Accounting Firm
101. INS	XBRL Instance Document
101. SCH	XBRL Taxonomy Extension Schema
101. CAL	XBRL Taxonomy Extension Schema Calculation Linkbase
101. DEF	XBRL Taxonomy Extension Schema Definition Linkbase
101. LAB	XBRL Taxonomy Extension Schema Label Linkbase
101. PRE	XBRL Taxonomy Extension Schema Presentation Linkbase

*     Filed herewith.

77

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

	SEADRILL PARTNERS LLC (Registrant)
Date: April 30, 2021
	By:	/s/ John T. Roche
	Name:	John T. Roche
	Title:	Chief Executive Officer of Seadrill Partners LLC (Principal Executive Officer of Seadrill Partners LLC)

Index to Consolidated Financial Statements of Seadrill Partners LLC

(Debtor-in-Possession)

Report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm	F- 2
Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018	F- 4
Consolidated Balance Sheets as at December 31, 2020 and 2019	F- 5
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018	F- 6
Consolidated Statements of Changes in Members' Capital for the years ended December 31, 2020, 2019 and 2018	F- 7
Notes to Consolidated Financial Statements	F- 8

F- 1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of Seadrill Partners LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Seadrill Partners LLC and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, of changes in members’ capital and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (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 as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Substantial Doubt About the Company’s Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 and Note 4 to the consolidated financial statements, on December 1, 2020, the Company and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. Uncertainties inherent in the bankruptcy process raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to this matter are also described in Note 1 and Note 4. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements 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 consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

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

Impairment of drilling units

As described in Notes 2, 10 and 15 to the consolidated financial statements, the Company’s carrying value of drilling units was $428.3 million as of December 31, 2020. Management reviews the carrying value of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. Management first assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to be generated from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, then the carrying value of the asset is compared to the discounted future net cash flows, using a relevant weighted-average cost of capital. The impairment loss to be recognized during the period, is the amount by which the carrying value of the asset exceeds the discounted future net cash flows. As disclosed by management, cash flows used in recoverability assessments are prepared for each rig and based on the assumptions which are developed in the annual budgeting process and the five-year plan. These include assumptions about long-term day rates by rig, long-term economic utilization, contract probabilities, operating expenses, estimated maintenance and inspection costs, reactivation costs and timing for the cold stacked rigs, and recycling probability. The discount rate is considered to be a key assumption in the discounted future net cash flows. In 2020, the following events or changes in circumstances indicated that the carrying amount of the drilling units may not be recoverable: the oil

F- 2

price collapse in the beginning of 2020 and main industry players have not completed scrapping programs as expected. This resulted in an impairment expense of $4,210.4 million during 2020.

The principal considerations for our determination that performing procedures relating to the impairment of drilling units is a critical audit matter are (i) the significant judgment by management when developing the forecasted cash flows associated with drilling units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant estimates and assumptions related to long term day rates by rig, contract probabilities, reactivation timing for the cold stacked rigs, recycling probability and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing management’s process for developing the future net cash flows, (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness, accuracy, and relevance of the underlying data used in the model; and (iv) evaluating the significant estimates and assumptions used by management related to the long term day rates by rig, contract probabilities, reactivation timing for cold stacked rigs, recycling probability, and the weighted-average cost of capital used to determine the discount rate. Evaluating management’s significant estimates and assumptions involved evaluating whether the estimates and assumptions used by management were reasonable considering (i) the current and past performance of the drilling unit; (ii) the consistency with external market and industry forecast data; (iii) sensitivity analysis to understand the impact of changes to significant assumptions and (iv) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s weighted-average cost of capital used to determine the discount rate.

Uncertain tax positions

As described in Notes 2 and 7 to the consolidated financial statements, the Company had a total amount of unrecognized tax benefits of $39.2 million as of December 31, 2020. As disclosed, management recognizes tax liabilities based on an assessment of whether their tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence. Management recognizes liabilities for uncertain tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount that is more than 50% likely of being realized upon settlement. While the annual tax provision is based on the information available to management at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.

The principal considerations for our determination that performing procedures relating to the uncertain tax positions is a critical audit matter are (i) the significant judgment applied by management to assess whether their tax positions are more likely than not sustainable; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s timely identification and accurate measurement of uncertain tax positions; (iii) the evaluation of audit evidence available to support the tax liabilities for uncertain tax positions is complex and resulted in significant auditor judgment as the nature of the evidence is often highly subjective; and (iv) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others (i) testing the completeness, accuracy and relevance of data used in the calculation of the liability for uncertain tax positions, including agreements, and tax positions in various jurisdictions, and the related final tax returns; (ii) testing the liability for uncertain tax positions by jurisdiction, including management’s assessment of the technical merits of tax positions and estimates of the amount of tax benefit expected to be sustained; and (iii) evaluating the status and results of income tax audits with the relevant tax authorities. Professionals with specialized skill and knowledge were used to assist in the evaluation of the completeness and measurement of the Company’s uncertain tax positions, including assessing the reasonableness of management’s determination whether tax positions are more-likely-than-not of being sustained and the amount of potential benefit to be realized, and the application of relevant tax laws.

/s/ PricewaterhouseCoopers LLP

Watford, United Kingdom

April 30, 2021

We have served as the Company's auditor since 2012.

F- 3

SEADRILL PARTNERS LLC

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF OPERATIONS

for the years ended December 31, 2020, 2019 and 2018

(In $ millions, except per unit data)

	Note		2020	2019	2018
Operating revenues
Contract revenues			525.9	686.5	797.5
Reimbursable revenues			11.1	20.7	31.2
Other revenues	8	*	1.1	42.8	209.5
Total operating revenues			538.1	750.0	1,038.2
Operating expenses
Vessel and rig operating expenses		*	(255.9)	(325.3)	(278.2)
Depreciation	15		(230.8)	(275.9)	(280.3)
Amortization of favorable contracts	14		(40.4)	(45.1)	(45.1)
Reimbursable expenses			(10.2)	(19.4)	(28.6)
Selling, general and administrative expenses		*	(34.4)	(34.4)	(45.8)
Total operating expenses			(571.7)	(700.1)	(678.0)
Other operating items
Loss on impairment of goodwill			—	—	(3.2)
Revaluation of contingent consideration			—	0.7	—
Impairment of long-lived assets	10		(4,210.4)	—	—
Total other operating items	9		(4,210.4)	0.7	(3.2)
Operating (loss)/income			(4,244.0)	50.6	357.0
Financial items
Interest income			6.1	20.3	47.1
Interest expense	11	*	(235.3)	(262.5)	(263.7)
(Loss)/gain on derivative financial instruments	20	*	(16.1)	(27.7)	24.9
Currency exchange (loss)/gain			(2.7)	(2.6)	0.2
Reorganization items, net	4		(49.8)	—	—
Other financial expenses			(17.1)	(1.4)	(4.8)
Total financial items			(314.9)	(273.9)	(196.3)
(Loss)/income before income taxes			(4,558.9)	(223.3)	160.7
Income tax (expense)/benefit	7		(30.0)	36.1	(86.7)
Net (loss)/income			(4,588.9)	(187.2)	74.0
Net (loss)/income attributable to Seadrill Partners LLC members			(2,550.9)	(92.9)	56.1
Net (loss)/income attributable to the non-controlling interest			(2,038.0)	(94.3)	17.9
(Loss)/Earnings per unit (common and subordinated)
Common unitholders (basic and diluted) (U.S. Dollars)			(277.80)	(10.12)	7.45
Subordinated unitholders (basic and diluted) (U.S. Dollars)			(277.80)	(10.12)	—

* Includes transactions with related parties. Refer to Note 19 - "Related party transactions".

A Statement of Other Comprehensive Income has not been presented as there are no items recognized in other comprehensive income.

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 4

SEADRILL PARTNERS LLC

(Debtor-in-Possession)

CONSOLIDATED BALANCE SHEETS

as at December 31, 2020 and 2019

(In $ millions)

	Note	2020	2019
ASSETS
Current assets
Cash and cash equivalents		362.0	560.0
Restricted cash	12	16.4	—
Accounts receivable, net	13	56.6	146.7
Amount due from related party	19	7.6	6.9
Other current assets	14	45.0	119.5
Total current assets		487.6	833.1
Non-current assets
Drilling units	15	428.3	4,840.8
Deferred tax assets	7	3.3	6.1
Other non-current assets	14	8.0	—
Total non-current assets		439.6	4,846.9
Total assets		927.2	5,680.0
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities
Debt due within twelve months	16	—	301.4
Trade accounts payable and accruals		4.2	17.4
Current portion of deferred and contingent consideration to related party	19	—	31.5
Related party payable	19	7.4	79.5
Other current liabilities	17	56.3	103.5
Total current liabilities		67.9	533.3
Liabilities subject to compromise	4	2,879.1	—
Non-current liabilities
Long-term debt	16	—	2,576.8
Deferred tax liability	7	1.0	2.0
Other non-current liabilities	17	44.4	44.2
Total non-current liabilities		45.4	2,623.0
Commitments and contingencies (see Note 22)
Equity
Members' Capital:
Common unitholders (issued 7,527,830 units as at December 31, 2020 and December 31, 2019)		(944.5)	1,146.8
Subordinated unitholders (issued 1,654,335 units as at December 31, 2020 and December 31, 2019)		(371.4)	88.2
Total members' capital		(1,315.9)	1,235.0
Non-controlling interest	18	(749.3)	1,288.7
Total (deficit)/equity		(2,065.2)	2,523.7
Total liabilities and equity		927.2	5,680.0

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 5

SEADRILL PARTNERS LLC

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF CASH FLOWS

for the years ended December 31, 2020, 2019 and 2018

(In $ millions)

	2020	2019	2018
Cash Flows from Operating Activities
Net (loss)/income	(4,588.9)	(187.2)	74.0
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Depreciation	230.8	275.9	280.3
Amortization of deferred loan charges	44.2	11.7	12.4
Amortization of favorable contracts	40.4	45.1	45.1
Impairment of long-lived assets	4,210.4	—	—
Loss on impairment of goodwill	—	—	3.2
Unrealized (gain)/loss related to derivative financial instruments	(4.0)	27.6	(38.9)
Payment for long term maintenance	(19.3)	(81.4)	(91.6)
Non-cash reorganization items	42.9	—	—
Reversal of credit risk on derivatives	7.1	—	—
Deferred tax expense	1.7	3.2	0.7
Gain on revaluation of contingent consideration	—	(0.7)	—
Accretion of discount on deferred consideration	1.9	3.2	5.3
Changes in operating assets and liabilities, net of effect of acquisitions
Trade accounts receivable	90.1	4.2	103.2
Prepaid expenses and accrued income	(32.4)	(2.0)	(3.6)
Trade accounts payable	0.1	(8.3)	(11.2)
Related party balances	(1.3)	(47.3)	(12.9)
Other assets	38.7	0.7	15.5
Other liabilities	104.7	(69.4)	56.5
Changes in deferred revenue	(2.1)	(1.3)	(3.4)
Other, net	—	—	(0.5)
Net cash provided by/(used in) operating activities	165.0	(26.0)	434.1
Cash Flows from Investing Activities
Additions to drilling units	(9.4)	(29.7)	(23.4)
Net cash used in investing activities	(9.4)	(29.7)	(23.4)

Cash Flows from Financing Activities
Repayments of debt	(306.6)	(192.6)	(296.4)
Repayments of related party debt	—	—	(24.7)
Contingent consideration paid	(30.6)	(30.0)	(34.0)
Cash distributions	—	(3.3)	(55.4)
Repayment of shareholder loan	—	—	(6.2)
Net cash used in financing activities	(337.2)	(225.9)	(416.7)
Effect of exchange rate changes on cash	—	—	(1.0)
Net decrease in cash and cash equivalents	(181.6)	(281.6)	(7.0)
Cash and cash equivalents at beginning of the year	560.0	841.6	848.6
Cash and cash equivalents, including restricted cash, at the end of year	378.4	560.0	841.6
Supplementary disclosure of cash flow information
Interest and other financial items paid	68.9	247.6	261.3
Taxes paid	21.7	50.1	24.9

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 6

SEADRILL PARTNERS LLC

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS'

CAPITAL

for the years ended December 31, 2020, 2019 and 2018

(In $ millions)

	Members' Capital
	Common Units	Subordinated Units	Total Before Non- controlling interest	Non- controlling interest	Total (Deficit)/ Equity
Consolidated balance at December 31, 2017	1,208.9	94.8	1,303.7	1,398.1	2,701.8
Net income	46.0	10.1	56.1	17.9	74.0
Cash distributions	(30.1)	—	(30.1)	(25.3)	(55.4)
Repayment of shareholder loan	—	—	—	(6.2)	(6.2)
Consolidated balance at December 31, 2018	1,224.8	104.9	1,329.7	1,384.5	2,714.2
Net loss	(76.2)	(16.7)	(92.9)	(94.3)	(187.2)
Cash distributions	(1.8)	—	(1.8)	(1.5)	(3.3)
Consolidated balance at December 31, 2019	1,146.8	88.2	1,235.0	1,288.7	2,523.7
Net loss	(2,091.3)	(459.6)	(2,550.9)	(2,038.0)	(4,588.9)
Consolidated balance at December 31, 2020	(944.5)	(371.4)	(1,315.9)	(749.3)	(2,065.2)

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F- 7

SEADRILL PARTNERS LLC

(Debtor-in-Possession)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - General information

Background

Seadrill Partners LLC (the "Company", "we" or "our") is incorporated in the Republic of the Marshall Islands. We provide offshore drilling services to the oil and gas industry. As at December 31, 2020 we owned and operated 11 offshore drilling units. Our fleet consists of drillships, semi-submersible rigs and tender rigs for operations in shallow and deepwater areas, as well as benign and harsh environments.

As of October 24, 2012 we were listed on the New York Stock Exchange ("NYSE"). On December 11, 2019, the NYSE filed a Form 25 with the SEC in connection with the delisting and deregistration of our common units. Delisting of our common units from the NYSE became effective 10 days after the filing date of the Form 25. The Form 25 was filed as part of delisting procedures resulting from the company's low market capitalization, as we previously announced on September 6, 2019. Our common units currently trade on the over-the-counter market ("OTC") under the ticker symbol "SDLPQ".

Chapter 11 proceeding and going concern

Since the mid-2010s, the industry has experienced a sustained decline in oil prices which has culminated in an industry-wide supply and demand imbalance. During this period, market dayrates for drilling rigs have been lower than was anticipated when the debt associated with acquiring our rigs was incurred. This challenging business climate was further destabilized by challenges that have arisen due to the COVID-19 pandemic. The actions taken by governmental authorities around the world to mitigate the spread of COVID-19 have had a significant negative effect on oil consumption. This has led to a further decrease in the demand for our services and has had an adverse impact on our business and financial condition.

On December 1, 2020 Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petition for reorganization under Chapter 11 triggering a stay on enforcement of remedies with respect to our debt obligations. As at December 31, 2020 we had total debt outstanding of $2,727.1 million under our credit facilities, all of which matures in the first quarter of 2021. As part of the Chapter 11 proceedings, the Debtors were granted “first-day” relief which enables us to continue operations without interruption. On February 12, 2021, the Debtors and certain of their prepetition lenders executed a plan support agreement, which contemplates a series of restructuring transactions that will equitize approximately $2.7 billion in secured term loan obligations and select go-forward, value maximizing services providers.

As of December 31, 2020, we had cash and cash equivalents of $378.4 million of which $362 million was unrestricted and we have implemented, and will continue to implement, various measures to preserve liquidity. These include primarily deferrals of capital expenditures and cold stacking the drilling units, as well as an increased focus on operating efficiency and reductions in corporate and overhead expenditures. Whilst we believe this should provide sufficient liquidity for the 12 month period from the issuance of these financial statements to allow us to complete a comprehensive restructuring, the process is difficult to predict and subject to factors outside of our control. We are subject to numerous risks associated with the bankruptcy proceedings and there can be no assurance that we will agree a plan of reorganization that is acceptable to our creditors, nor that the Bankruptcy Court would confirm such a plan once agreed.

These conditions and events raise substantial doubt as to our ability to continue as a going concern for the twelve months after the date our financial statements are issued. Financial information in this report has been prepared on a going concern basis of accounting, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Financial information in this report does not reflect the adjustments to the carrying values of assets, liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.

Basis of presentation

The Consolidated Financial Statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States Dollars ("U.S. Dollars" or "US$") rounded to the nearest million, unless otherwise stated.

Basis of consolidation

The financial statements include the results and financial position of all companies in which we directly or indirectly hold more than 50% of the voting control. We eliminate all intercompany balances and transactions.

We control Seadrill Operating LP and its majority owned subsidiaries as well as Seadrill Capricorn Holdings LLC and its majority owned subsidiaries. We separately present within equity on our Consolidated Balance Sheets the ownership interests attributable to parties with non-controlling interests in our Consolidated subsidiaries, and we separately present net income attributable to such parties in our Consolidated Statements of Operations.

Bankruptcy accounting

Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petitions on December 1, 2020 (the "Petition Date") to commence prearranged reorganization proceedings under Chapter 11 of Title 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the Southern District of Texas (the “Bankruptcy Court”) case number 20-35740. During the pendency of the

F- 8

Chapter 11 proceedings, the Debtors will operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provision of the Bankruptcy Code. For further information refer to Note 4 - "Chapter 11 Proceedings".

Since the Petition Date, we prepared our Consolidated Financial Statements under Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 requires that the financial statements, for periods subsequent to filing bankruptcy petitions, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net" on the Company’s Consolidated Statements of Operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the Consolidated Balance Sheets, particularly liabilities. Pre-petition obligations that may have been impacted by Chapter 11 reorganization process were classified on the Consolidated Balance Sheets within "Liabilities subject to compromise".

Note 2 - Accounting policies

The accounting policies set out below have been applied consistently to all periods in these Consolidated Financial Statements, unless otherwise noted.

Allowance for credit losses

We adopted accounting standard update 2016-13 Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The new guidance replaces the “incurred loss” model required under the previous guidance with a current “expected credit loss” (or CECL) model. The CECL model requires recognition of expected credit losses over the life of a financial asset upon its initial recognition. Comparative periods are presented under the previous guidance with an allowance against a receivable balance recognized only if it was probable that we would not recover the full amount due to us. We determined doubtful accounts on a case-by-case basis and considered the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. The CECL model applies to external trade receivables, related party receivables and other financial assets measured at amortized cost. We have determined that on transition and at December 31, 2020, the impact of the CECL model is not material and no credit loss adjustments have been applied.

The CECL model contemplates a broader range of information to estimate expected credit losses over the contractual lifetime of an asset. It also requires to consider the risk of loss even if it is remote. We estimate expected credit losses based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts of events which may affect the collectability. We estimate the CECL allowance using a “probability-of-default” model, calculated by multiplying the exposure at default by the probability of default by the loss given default by a risk overlay multiplier over the life of the financial instrument (as defined by ASU 2016-13).

Revenue from contracts with customers

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract with a customer. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments of service.

We recognize revenues for activities that correspond to a distinct time increment of service within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment of service, ratably over the estimated contract term.

We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required. Refer to Note 6 - "Revenue from contracts with customers".

Dayrate drilling revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment service it relates to. Revenue is recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract. The associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.

Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional

F- 9

contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as "reimbursable revenues" in our Consolidated Statements of Operations.

Local Taxes - In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.

Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.

Other revenues

Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 8 - ''Other revenues''. Revenue is recognized as the performance obligation is satisfied, which on our leased rigs is on a straight-line basis.

Related party revenues - Related party revenues relate to onshore support and offshore personnel provided to Seadrill.

Early termination fees - Other revenues also include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved. Refer to Note 19 - ''Related party transactions''.

Vessel and rig operating expenses

Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.

Mobilization and demobilization expenses

We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see "Deferred Contract Costs" above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.

We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract.

Repairs, maintenance and periodic surveys

Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.

Income taxes

Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Refer to Note 7 – "Taxation".

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits.

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. We recognize the income tax effects of intercompany sales or

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transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period of sale or transfer occurs.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as at the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Foreign currencies

The majority of our revenues and expenses are denominated in U.S. Dollars and therefore the majority of our subsidiaries use U.S. Dollars as their functional currency. Our reporting currency is also U.S. Dollars. For subsidiaries that maintain their accounts in currencies other than U.S. Dollars, we use the current method of translation whereby the Statements of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in members' capital.

Transactions in foreign currencies are translated into U.S. Dollars at the rates of exchange in effect at the date of the transaction. Foreign currency denominated monetary assets and liabilities are remeasured using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the Consolidated Statements of Operations.

Earnings Per Unit ("EPU")

We compute EPU using the two-class method set out in GAAP. We first allocate undistributed earnings for the period to the holders of common units, subordinated units and incentive distribution rights. This allocation is made in accordance with the cash distribution provisions contained in our First Amended and Restated Operating Agreement of the Company (the "Operating Agreement"). Unallocated earnings may be negative if amounts distributed are higher than total earnings. We allocate such deficits using the same cash distribution model.

We calculate the EPU for each category of units by taking the sum of the distributions to those units plus the allocation of those units undistributed earnings for the period and dividing this total by the weighted average number of units outstanding for the period. We don't have any potentially dilutive instruments and therefore don't present a diluted EPU. Refer to Note 23 - ''Earnings per unit and cash distributions''.

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. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets. Hierarchy Level 2 inputs are 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. Hierarchy Level 3 inputs are significant unobservable inputs, including those that require considerable judgment for which there is little or no market data. 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.

Current and non-current classification

Generally, assets and liabilities (excluding deferred taxes and liabilities subject to compromise) are classified as current assets and liabilities respectively if their maturity is within one year of the balance sheet date. In addition, we classify any derivative financial instruments whose fair value is a net liability as current. Current liabilities will include where amounts from lenders are payable on demand at their discretion due to event of default clauses being met.

Generally, assets and liabilities are classified as non-current assets and liabilities respectively, if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivative financial instruments whose fair value is a net asset as non-current.

Where the liabilities are subject to compromise as part of the Chapter 11 proceedings they are classified separately in the Consolidated Balance Sheet and neither classified as current or non-current.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with maturities of three months or less. Amounts are presented net of allowances for credit losses.

Restricted cash consists of bank deposits which are subject to restrictions due to legislation, regulation or contractual arrangements. Restricted cash amounts that are expected to be used after one year from balance sheet date are classified as non-current assets. Amounts are presented

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net of allowances for credit losses, which are assessed based on consideration of whether the balances have short-term maturities and whether the counterparty has an investment grade credit rating, limiting any credit exposure. Refer to Note 12 – "Restricted cash".

Receivables

Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount net of expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 13 - ''Accounts receivable''.

Contract assets and liabilities

Accounts receivables are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. If we recognize revenue ahead of this point, we also recognize a contract asset. Contract assets balances relate primarily to demobilization revenues recognized during the period but are contingent on future demobilization activities.

Contract liabilities include payments received for mobilization, rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. Amounts receivable from related parties are presented net of allowances for expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 19 - ''Related party transactions'' for details of balances and material transactions with related parties.

Use of estimates

Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

In assessing the recoverability of our drilling units carrying amounts, we make assumptions regarding estimated future cash flows, estimates in respect of residual value, day rates, drilling unit operating expenses and overhaul requirements.

Business combinations

We apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred.

Drilling units

Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up rigs, when new, is 30 years. The direct and incremental costs of significant capital projects, such as rig upgrades and reactivation projects, are capitalized and depreciated over the remaining life of the asset.

Drilling units acquired in a business combination are measured at fair value at the date of acquisition. Drilling units were also remeasured to fair value when we applied fresh start accounting at the date of emergence. Cost of property and equipment sold or retired, with the related accumulated depreciation and impairment is removed from the Consolidated Balance Sheet, and resulting gains or losses are included in the Consolidated Statement of Operations.

We re-assess the remaining useful lives of our drilling units when events occur which may impact our assessment of their remaining useful lives. These include changes in the operating condition or functional capability of our rigs, technological advances, changes in market and economic conditions as well as changes in laws or regulations affecting the drilling industry. Refer to Note 15 - ''Drilling units ''.

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: management commits to a plan to sell the asset (disposal group), the asset is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets, an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset is probable, and transfer of the asset is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

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Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to be generated from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, we then compare the carrying value of the asset with the discounted future net cash flows, using a relevant weighted-average cost of capital. The impairment loss to be recognized during the period, is the amount by which the carrying value of the asset exceeds the discounted future net cash flows.

Favorable drilling contracts - intangible assets

Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the Consolidated Statements of Operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.

Derivative Financial Instruments and Hedging Activities

Our derivative financial instruments are measured at fair value and are not designated as hedging instruments. Changes in their fair value are recorded as a gain or loss as a separate line item within "financial items" in the Consolidated Statements of Operations. We classify the asset or liability for derivative financial instruments within "other current assets" or "other current liabilities" in our Consolidated Balance Sheets. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements. Refer to Note 21 - ''Fair Value Measurement''.

Trade payables

Trade payables are liabilities to a supplier for a good or service provided to us.

Deferred charges

Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in "interest expense" in the Consolidated Statement of Operations.

Debt

We have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid. Refer to Note 16 - ''Debt''.

Loss contingencies

We recognize a loss contingency in the Consolidated Balance Sheets where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Refer to Note 22 - ''Commitments and contingencies''.

Equity allocation

Earnings and losses attributable to unitholders of Seadrill Partners are allocated to all unitholders on a pro rata basis for the purposes of presentation in the Consolidated Statements of Changes in Members' Capital. Earnings and losses attributable to unitholders for any period are first reduced for any cash distributions for the period to be paid to the holders of the incentive distribution rights.

At the time of the Company's initial public offering, the equity attributable to unitholders was allocated using the hypothetical amounts which would be distributed to the various unitholders on a liquidation of the Company ("hypothetical liquidation method"). This method has also been used to account for issuances of common units by the Company, and the deemed distributions from equity which resulted from acquisitions of drilling units from Seadrill.

Guarantees

Guarantees issued by us, excluding those that are guaranteeing our own performance, are recognized at fair value at the time that the guarantees are issued and reported in "other current liabilities" and "other non-current liabilities" in our Consolidated Balance Sheets. If it becomes probable that we will have to perform under a guarantee, we remeasure the liability if the amount of the loss can be reasonably estimated. The recognition of fair value is not required for certain guarantees such as the parent's guarantee of a subsidiary's debt to a third party. Financial guarantees written are assessed for credit losses and any allowance is presented as a liability for off-balance sheet credit exposures where the balance exceeds the collateral provided over the remaining instrument life. The allowance is assessed at the individual guarantee level, calculated by multiplying the balance exposed on default by the probability of default and loss given default over the term of the guarantee.

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Note 3 - Recent accounting standards

We adopted the following accounting standard updates ("ASUs") in the year:

a) ASU 2016-13 - Financial Instruments - Measurement of Credit Losses (Also 2018-19, 2019-04 & 2019-11)

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments, including ASU 2018-19, ASU 2019-04 and ASU 2019-11: Codification Improvements to Topic 326 ‘‘Financial Instruments-Credit Losses”. Topic 326 replaces the incurred loss impairment methodology (that recognizes losses when a probable threshold is met) with a requirement to recognize lifetime expected credit losses (measured over the contractual life of the instrument) immediately, based on information about past events, current conditions and forecasts of future economic conditions. Under the current expected credit loss ( the "CECL") measurement financial assets are reflected at the net amount expected to be collected from the financial asset, CECL measurement is applicable to financial assets measured at amortized cost as well as off-balance sheet credit exposures not accounted for as insurance (including financial guarantees).

Using the modified retrospective method, reporting periods beginning after January 1, 2020 are presented under Topic 326 while comparative periods continue to be reported in accordance with previously applicable GAAP and have not been restated. The adoption of Topic 326 did not have a material impact on our condensed consolidated financial statements.

b) ASU 2020-03 Financial Instruments: Codification Improvements

In March 2020, the FASB issued ASU 2020-03 Financial Instruments (Topic 825) - Codification Improvements. The amendments in this ASU propose seven clarifications to improve the understandability of existing guidance, including that fees between debtor and creditor and third-party costs directly related to exchanges or modifications of debt instruments include line-of-credit or revolving debt arrangements. We adopted the codification improvements that were effective on issuance from January 1, 2020 under the specified transition approach connected with each of the codification improvements. This amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2020.

c) Other accounting standard updates

We additionally adopted the following accounting standard updates in the year which did not have any material impact on our Consolidated Financial Statements and related disclosures:

•ASU 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.

•ASU 2018-13 Fair Value Measurement: Changes to the Disclosure Requirements for Fair Value Measurement.

•ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans.

•ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.

•ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities.

•ASU 2019-04 Codification Improvements to Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments.

•ASU 2019-08 Compensation—Stock Compensation (Topic 718) and Revenue from Contracts with Customers (Topic 606): Codification Improvements—Share-Based Consideration Payable to a Customer.

2) Recently issued accounting standards

Recently issued ASUs by the FASB that we have not yet adopted but which could affect our Consolidated Financial Statements and related disclosures in future periods:

a) ASU 2019-12 Income Taxes (Topic 740): Simplifying the accounting for income taxes

In December 2019, the FASB issued ASU 2019-12. The amendments in this update simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance will be effective from January 1, 2021 on a mainly prospective basis, with early adoption permitted. This amendment will have no material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2021.

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b) ASU 2020-04 Reference Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04. The amendments provide temporary optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The applicable expedients for us are in relation to modifications of contracts within the scope of Topics 310, Receivables, 470, Debt, and 842, Leases. This optional guidance may be applied prospectively from any date beginning March 12, 2020 and cannot be applied to contract modifications that occur after December 31, 2022. We are in the process of evaluating the impact of this standard update on our consolidated financial statements and related disclosures.

c) Other accounting standard updates issued by the FASB

As of April 30, 2021, the FASB have issued several further updates not included above. We do not currently expect any of these updates to affect our Consolidated Financial Statements and related disclosures either on transition or in future periods.

Note 4 - Chapter 11 Proceedings

Bankruptcy proceedings under Chapter 11

On December 1, 2020, Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”), triggering a stay on enforcement of remedies with respect to our debt obligations. As part of the Chapter 11 proceedings, the Debtors were granted “first-day” relief which enables us to continue operations without interruption. On February 12, 2021, the Debtors and certain of their prepetition lenders executed a plan support agreement, which contemplates a series of restructuring transactions that will equitize approximately $2.7 billion in secured term loan obligations and select go-forward, value maximizing services providers.

ASC 852-10, Reorganizations, applies to entities that have filed a petition for relief under Chapter 11 of the Bankruptcy Code. In accordance with ASC 852-10, transactions and events directly associated with the reorganization are required to be distinguished from the ongoing operations of the business. In addition, the guidance requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.

We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh-start accounting guidance upon emergence pursuant to a plan of reorganization.

Liabilities subject to compromise

Liabilities subject to compromise distinguish pre-petition liabilities which may be affected by the Chapter 11 proceedings from those that are not and those post-petition. These amounts represent our allowed claims and our best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. This is disclosed on a separate line in between current and non-current liabilities on the consolidated balance sheet.

Liabilities subject to compromise represent our estimate of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. Such claims remain subject to future adjustments which may result from: (i) negotiations; (ii) actions of the Bankruptcy Court; (iii) disputed claims; (iv) rejection of executory contracts and unexpired leases; (v) the determination as to the value of any collateral securing claims; (vi) proofs of claim; or (vii) other events. Such future adjustments will potentially be material.

Liabilities subject to compromise, as presented on the Consolidated Balance Sheet as at December 31, 2020, include the following:

(In $ millions)	2020
Senior undersecured or impaired external debt	2,727.1
Derivatives previously recorded at fair value	20.8
Accounts payable and other liabilities	24.4
Accrued interest payable	32.5
Amount due to related party	74.3
Liabilities subject to compromise	2,879.1

While operating as a Debtor-in-Possession under Chapter 11 of the Bankruptcy Code, the Debtors may sell, otherwise dispose of, liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business, in amounts other than those reflected in the Consolidated Financial Statements. Moreover, a plan of reorganization could materially change the amounts and classifications of assets and liabilities in the historical Consolidated Financial Statements.

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Interest expense

The Debtors have discontinued recording interest on the under-secured debt facility, classified under liabilities subject to compromise, from the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Consolidated Statement of Operations was $21.3 million.

Potential claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing.

All holders of pre-petition claims except governmental units were required to file proofs of claim by February 15, 2021 (the "Bar Date"). Governmental units holding claims against the Debtors are required to file proof of claim by May 30, 2021. At the Bar Date, 285 claims totaling approximately $3.2 billion had been filed with the Bankruptcy Court against the Debtors. Subsequent to this date, approximately 120 further claims have been processed but this has not materially impacted the overall amount claimed against the Debtors.

It is possible that claimants will file amended claims in the future, including claims amended to assign values to claims originally filed with no designated value. Through the claims resolution process, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We will file objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Claims we believe are allowable are reflected in "Liabilities Subject to Compromise" in the Consolidated Balance Sheets.

Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the number of claims filed, the claims resolution process will take additional time to complete, and it may continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Executory Contracts

Under the Bankruptcy Code, the Debtors have the right to assume, amend and assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a prepetition general unsecured claim for damages.

Reorganization items, net

Incremental costs incurred directly as a result of the Bankruptcy Filing and gains on the settlement of liabilities under the Plan are classified as "Reorganization items, net" in the Consolidated Statements of Operations. The following table summarizes reorganization items:

(In $ millions)	2020
Advisory and professional fees	7.1
Unamortized debt issuance costs	42.9
Interest income on surplus cash invested	(0.2)
Reorganization items, net	49.8

Condensed Combined Debtors Financial Statements

As the non-debtor entities do not materially contribute to the Group financial position, we have not presented condensed combined financial statements specific to the Debtor group as a separate disclosure. For the Group financial position, please refer to the consolidated financial statements included herein.

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Note 5 – Segment information

Operating segment

We regard our fleet as one single operating segment. The Chief Operating Decision Maker, which is the Board of Directors, review performance at this level as an aggregated sum of assets, liabilities and operating income.

A breakdown of our revenues by customer for the years ended December 31, 2020, 2019 and 2018 is as follows: 

	2020		2019		2018
BP	75.8	%	67.6	%	68.0	%
Reliance	8.6	%	—	%	—	%
ExxonMobil	8.3	%	11.0	%	0.3	%
Petronas	5.5	%	9.9	%	—	%
Chevron	—	%	7.2	%	8.5	%
Tullow	—	%	—	%	19.8	%
Other	1.8	%	4.3	%	3.4	%
Total	100	%	100	%	100	%

Geographic Data

Revenues are attributed to geographical areas based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the revenues for the years ended December 31, 2020, 2019 and 2018 and fixed assets as of December 31, 2020 and 2019 by geographic area:

Revenues

(In $ millions)	2020	2019	2018
United States	409.4	539.1	618.1
India	46.0	—	—
Canada	45.2	60.9	85.3
Malaysia	36.9	40.1	—
Thailand	0.2	53.8	88.7
Gabon	0.2	21.2	—
Myanmar	—	17.8	—
Ghana	—	—	205.5
Other	0.2	17.1	40.6
Total	538.1	750.0	1,038.2

Fixed Assets—Drilling Units (1)  

(In $ millions)	2020	2019
United States	153.8	2,561.7
Malaysia	88.2	607.1
India	53.9	—
Canada	53.8	451.7
Aruba	51.5	—
Singapore	27.1	108.8
Namibia	—	502.5
Norway	—	499.2
Thailand	—	109.8
Total	428.3	4,840.8

(1)The fixed assets referred to in the table above include the 11 drilling units at December 31, 2020 and December 31, 2019. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

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Note 6 – Revenue from contracts with customers

The following table provides information about receivables and contract liabilities from our contracts with customers:

(In $ millions)	2020	2019
Accounts receivable, net	56.6	146.7
Current contract liabilities (deferred revenues) (1)	0.9	3.0

(1)  Current contract liabilities balances are included in "other current liabilities" in our Consolidated Balance Sheets as at December 31, 2020.

Significant changes in the contract liabilities balances during the year ended December 31, 2020 are as follows:

(In $ millions)	2020	2019
Contract liabilities at start of period	3.0	6.4
Decrease due to amortization of revenue that was included in the beginning contract liability balance	(3.0)	(9.3)
Increase due to cash received, excluding amounts recognized as revenue	0.9	5.9
Contract liabilities at end of period	0.9	3.0

The deferred revenues balance of $0.9 million reported in "other current liabilities" at December 31, 2020 is expected to be realized within the next twelve months.

Note 7 – Taxation

Income taxes consist of the following:

(In $ millions)	2020	2019	2018
Current tax expense / (benefit):
U.K.	—	—	(0.3)
Foreign	28.3	(39.3)	86.3
Total current tax expense / (benefit)	28.3	(39.3)	86.0
Deferred tax expense / (benefit):
Foreign	1.7	3.2	0.7
Total income tax expense / (benefit)	30.0	(36.1)	86.7

Seadrill Partners LLC is tax resident in the U.K. The Company's controlled affiliates operate and earn income in several countries and are subject to the laws of taxation within those countries. Currently some of the Company's controlled affiliates formed in the Marshall Islands along with all those incorporated in the U.K. (none of whom presently own or operate rigs) are resident in the U.K. and are subject to U.K. tax. Subject to changes in the jurisdictions in which the Company's drilling units operate and/or are owned, differences in levels of income and changes in tax laws, the Company's effective income tax rate may vary substantially from one reporting period to another.

The Company's effective income tax rate for each of the years ended on December 31, 2020, 2019 and 2018 differs from the U.K. statutory income tax rate as follows:

	2020		2019		2018
U.K. statutory income tax rate	19.0	%	19.0	%	19.0	%
Non-U.K. taxes	(19.7)	%	(2.8)	%	35.0	%
Effective income tax rate	(0.7)	%	16.2	%	54.0	%

Due to the CARES Act in the U.S., the Company recognized a tax benefit of $6 million by carrying back net operating losses to previous years.

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

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Our deferred tax assets consist of the following:

(In $ millions)	2020	2019
Provisions	54.9	0.6
Net operating losses carry forward	221.5	77.5
Interest carry forward	—	29.6
Property, plant and equipment	174.5	—
Other	3.6	5.3
Gross deferred tax assets	454.5	113.0
Valuation allowance	(451.6)	(107.1)
Deferred tax asset, net of valuation allowance	2.9	5.9

Our deferred tax liabilities consist of the following:

(In $ millions)	2020	2019
Property, plant and equipment	—	0.1
Unremitted earnings of subsidiaries	0.6	1.7
Gross deferred tax liabilities	0.6	1.8
Net deferred tax asset	2.3	4.1

As of December 31, 2020, deferred tax assets related to net operating loss ("NOL") carryforwards were $221.5 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $51.9 million which will not expire and $169.6 million that will expire between 2022 and 2037 if not utilized. Primarily due to the impairment of rigs, we generated deferred tax assets related to NOL of $218.9 million and Property, plant and equipment (“PP&E”) of $174.5 million in 2020. We establish a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change. Our valuation allowance primarily consists of $220.7 million on NOL carryforward, $174.7 million on PP&E and $55.4 million on interest carryforward.

Uncertain tax positions

As of December 31, 2020, the Company had a total amount of unrecognized tax benefit of $39.2 million (December 31, 2019: $40.2 million), excluding of interest and penalties included in "other non-current liabilities" on the Consolidated Balance Sheets. The changes to the Company's balance related to unrecognized tax benefits were as follows:

(In $ millions)	2020	2019
Balance beginning of year	40.2	101.6
Increases as a result of positions taken in prior years	—	1.1
Decreases as a result of positions taken in prior years	(1.0)	(60.7)
Settlements	—	(1.8)
Unrecognized tax benefits	39.2	40.2

Accrued interest and penalties totaling $5.2 million as of December 31, 2020 (December 31, 2019: $4 million) were included in "other non-current liabilities" on the Consolidated Balance Sheets. The Company recognized interest and penalty expense of $1.2 million as "Income tax (expense)/benefit" in the Consolidated Statements of Operations during the year ended December 31, 2020 (December 31, 2019: $12.4 million benefit and December 31, 2018: $8.4 million expense).

As of December 31, 2020, $44.4 million of our unrecognized tax benefit, including penalties and interest, would have a favorable impact to the Company's effective tax rate if recognized.

Tax examinations

The Company is subject to taxation in various jurisdictions. The Ghana tax authorities have issued a series of assessments with respect to our returns for certain years up to 2018 in respect of indirect and direct taxes. The assessments are for an aggregate amount of $18 million as of the date of this report. These assessments are being robustly contested including filing relevant appeals. An adverse outcome on these proposed assessments could result in a material adverse impact on our Consolidated Balance Sheets, Statement of Operations or Cash flows.

The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:

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Jurisdiction	Earliest Open Year
United States	2016
Nigeria	2012
Ghana	2013

Note 8 – Other revenues

Other revenues comprise the following items: 

(In $ millions)	2020	2019	2018
Early termination revenue	—	41.0	204.9
Related party other revenues	1.1	1.8	4.6
Total	1.1	42.8	209.5

Early termination revenue for the year ended December 31, 2019 was $41 million, relating to termination fees recognized for the West Capricorn and West Vencedor.

Early termination revenue for the year ended December 31, 2018 was $204.9 million, relating to the West Leo litigation judgment (refer to Note 22 - ''Commitments and contingencies'' for further information).

Related party other revenues primarily relate to revenue from the sale of inventories and spare parts to Seadrill. Please refer to Note 19 – "Related party transactions" for further detail on related party other revenues.

Note 9 – Other operating items

Other operating items comprise the following: 

(In $ millions)	2020	2019	2018
Loss on impairment of goodwill	—	—	(3.2)
Revaluation of contingent consideration	—	0.7	—
Impairment of long-lived assets	(4,210.4)	—	—
Total	(4,210.4)	0.7	(3.2)

During the year ended December 31, 2020 we recognized an impairment against our long-lived assets of $4,210.4 million. For further information refer to Note 10 - "Impairment of long-lived assets".

There was a gain on revaluation of contingent consideration of $0.7 million for the year ended December 31, 2019. This gain resulted from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015.

During the year ended December 31, 2018, we recognized a loss on impairment of goodwill following early adoption of ASU 2017-04, Intangibles. For further information refer to Note 3 - ''Recent accounting standards''.

Note 10 - Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. In 1Q20, as a result of the deteriorating market due to COVID-19 and oil price declines, there was an impairment triggering event and we recognized an impairment of $922.9 million in respect of certain idle drilling units. In 4Q20, our view was that the challenging market conditions are likely to persist for a sustained period and that certain of our cold stacked units are unlikely to return to the working fleet, so have concluded there is a further impairment triggering event for our drilling unit fleet and we recognized an impairment of $3,287.5 million.

On assessment of asset recoverability through an estimated undiscounted future net cash flow we calculated the value to be lower than the carrying value for all of our rigs, of which we recognized full impairments of the West Sirius and West Leo and partial impairments for all other rigs. This resulted in impairment expenses of $4,210.4 million during 2020 which were classified within “impairment of long-lived assets” on our Consolidated Statement of Operations for the year ended December 31, 2020.

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Note 11 - Interest expense

Interest expense consists of the following:

(In $ millions)	2020	2019	2018
Interest on debt facilities (1)	189.2	246.3	245.3
Loan fee amortization (2)	44.2	12.3	12.7
Other (3)	1.9	3.9	5.7
Total interest expense	235.3	262.5	263.7

(1) We are charged interest on our debt facilities at rates explained in Note 16 - "Debt". As a result of filing for Chapter 11, no interest has been recognized from December 1, 2020. For further details refer to Note 4 - "Chapter 11 Proceedings".

(2) We incur loan fees on our debt facilities that are amortized over the term of the loan. The increase in 2020 is due to commitment and exit fees incurred on the new super senior loans. For further details refer to Note 16 - "Debt".

(3) Other interest expense primarily relates to the unwind of the discount on contingent consideration payable to Seadrill. For further details refer to Note 19 - "Related party transactions".

Note 12 - Restricted cash

Restricted cash consists of $16.4 million as at December 31, 2020 (December 31, 2019: nil) for cash held as collateral for a guarantee with Danske Bank to provide security for the payment, discharge and performance of secured obligations.

Note 13 – Accounts receivable

Accounts receivable are held at their nominal amount less an allowance for expected credit losses. The adoption of ASC 326 on January 1, 2020 did not have a material impact on our third-party accounts receivable balances either on transition or at the year end. In calculating the expected credit losses we assumed that the accounts receivable are performing, mature within three months and have a Baa3 credit rating. Refer to Note 2 - "Accounting policies" for further information.

Note 14 – Other assets

Other assets include the following:

(In $ millions)	2020	2019
Intangible asset - Favorable contracts	—	40.4
Mobilization revenue receivables	—	22.3
Prepaid expenses	26.7	14.1
Income taxes receivable	13.0	19.3
VAT receivable	5.7	10.6
Deferred mobilization costs	3.0	7.5
Reimbursable amounts due from customers	1.5	3.5
Other	3.1	1.8
Total other assets	53.0	119.5

Other assets are presented in our Consolidated Balance Sheet as follows:

(In $ millions)	2020	2019
Other current assets	45.0	119.5
Other non-current assets (1)	8.0	—
Total other assets	53.0	119.5

(1) Relates to prepaid Directors and Officers insurance cover relating to tail back claims in the Chapter 11 process.

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Mobilization revenue receivables

Under our contracts for the West Auriga and West Vela, we are paid for mobilization activities over the contract term. We recorded a financial asset equal to the fair value of this future stream of payments when we acquired these drilling units from Seadrill. We collected these amounts over the term of the drilling contracts which completed in October 2020 and November 2020, respectively. We record the unwind of the time value of money discount as interest income.

Favorable contracts

Favorable drilling contracts are recorded as intangible assets at fair value on the date of acquisition less accumulated amortization. The amounts recognized represent the net present value of the existing contracts at the time of acquisition compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. The estimated favorable contract values have been recognized and amortized on a straight line basis over the terms of the contracts, ranging from two to five years.

Favorable contracts to be amortized relate to the favorable contracts acquired with the West Auriga and the West Vela from Seadrill as at December 31, 2020. These were fully amortized in October 2020 and November 2020 respectively. The gross carrying amounts and accumulated amortization included in "other current asset"' and "other non-current assets" in the Consolidated Balance Sheets were as follows:

	2020			2019
(In $ millions)	Gross carrying amount	Accumulated amortization	Net carrying amount	Gross carrying amount	Accumulated amortization	Net carrying amount
Intangible assets- Favorable contracts
Balance at beginning of period	357.3	(316.9)	40.4	357.3	(271.8)	85.5
Amortization of favorable contracts	—	(40.4)	(40.4)	—	(45.1)	(45.1)
Balance at end of period	357.3	(357.3)	—	357.3	(316.9)	40.4

Note 15 – Drilling units 

The below table shows the gross value and net book value of our drilling units at December 31, 2020 and December 31, 2019.

(In $ millions)	Cost	Accumulated depreciation	Net Book Value
Opening balance as at January 1, 2019	6,714.0	(1,708.4)	5,005.6
Additions	111.1	—	111.1
Depreciation	—	(275.9)	(275.9)
Closing balance as at December 31, 2019	6,825.1	(1,984.3)	4,840.8
Additions	28.7	—	28.7
Impairment	(4,210.4)	—	(4,210.4)
Depreciation	—	(230.8)	(230.8)
Closing balance as at December 31, 2020	2,643.4	(2,215.1)	428.3

Depreciation related to our drilling units was $230.8 million, $275.9 million and $280.3 million for the years ended December 31, 2020, 2019 and 2018 respectively.

Each of our drilling units has been pledged as collateral under our debt agreements. Please refer to Note 16 – "Debt" for further details.

We recognized an impairment expense of $4,210.4 million which was classified within "impairment of long-lived assets" on our Consolidated Statement of Operations for the year ended December 31, 2020. Please refer to Note 10 - "Impairment of long-lived assets" for further details.

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Note 16 – Debt

As at December 31, 2020 and December 31, 2019, we had the following debt amounts outstanding:

(In $ millions)	2020	2019
External debt agreements
Term Loan B	2,727.1	2,607.6
West Vela Facility	—	151.0
West Polaris Facility	—	114.9
Tender Rig Facility	—	18.6
Total external debt	2,727.1	2,892.1
Less: Debt balance held as subject to compromise	(2,727.1)	—
Debt balance not subject to compromise	—	2,892.1

Chapter 11 Proceedings

We filed for Chapter 11 bankruptcy protection on December 1, 2020 which triggered an event of default under the Term Loan B. As a result, the outstanding balance on this loan was classified within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings".

On filing for Chapter 11, $42.9 million of unamortized debt issuance costs on the Term Loan B were expensed and recognized within "Reorganization items, net" in the Consolidated Statement of Operations and no further interest was recorded on the Term Loan B from that point.

Term Loan B

Our Term Loan B facilities ("TLB") initially consisted of a term loan and a linked $100 million revolving credit facility. We initially borrowed $1.8 billion under the term loan on February 21, 2014 and then a further $1.1 billion on June 26, 2014. This loan is subject to a 1% per year ($29 million) amortization payment with the balance of the loan then being repayable in February 2021. The revolving credit facility matured in February 2019.

We agreed with the TLB lenders to amend the TLB agreement in July and October 2020 respectively, whereby the majority of the TLB interest that was due on June 30, 2020 and September 30, 2020 was converted into super senior loans ($8 million of TLB interest was cash settled to lenders that withheld consent). As a result, $63.7 million and $63.3 million super senior loans, maturing in February 2021 were created. These loans each included a non-cash $20 million commitment fee and an exit fee of 10% in addition to the interest settled through issuance of the loans.

We had a total of $2,727.1 million outstanding on the TLB at December 31, 2020

During the year ended December 31, 2020, we paid interest of LIBOR + 6% on the original term loan and LIBOR + 10% on the super senior loans. LIBOR is subject to a 1% floor. As of the date of filing for Chapter 11 we are subject to an additional 2% default interest, however we have discontinued recording interest. For further information refer to Note 4 - "Chapter 11 Proceedings".

Following an amendment to the TLB agreement, and the repayment of the other loan facilities (see below) all rigs are pledged as collateral vessels under the TLB. The net book value of these drilling units at December 31, 2020 was $428.3 million. We have also pledged substantially all the assets of our subsidiaries, which own or charter the collateral vessels as well as our investments in those companies.

West Vela facility

The West Vela facility consisted of a term loan with four tranches. We initially incurred the liability to repay $443 million under this term loan when we acquired the West Vela from Seadrill in November 2014. The loan was subject to amortization payments of $40.3 million per year. We made a prepayment of $46.7 million in August 2017 and further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The $120.8 million balloon payment was repaid in July 2020.

We paid interest on the term loan at LIBOR plus a margin of between 3.35% and 4%, inclusive of guarantee fees, depending on the tranche.

West Polaris facility

The West Polaris facility consisted of a term loan and a linked revolving credit facility. We initially incurred the liability to repay $226 million under this term loan and $100 million under the revolving credit facility when we acquired the West Polaris from Seadrill in June 2015. The loan was subject to amortization payments of $36 million per year. We made a prepayment of $37.4 million in August 2017 and further prepayments of $9.4 million in February 2018 and August 2018. The $93.8 million balloon payment was repaid in July 2020.

We paid interest on the term loan and revolving credit facility at LIBOR plus a margin of 3.25%. We also paid a commitment fee of 1.3% on any unused portion of the revolving credit facility.

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Tender rig facility

The Tender Rig facility consisted of two term loans. We initially borrowed $100.5 million and $93.1 million under intercompany loans from Seadrill when we acquired the T-15 and T-16 in May 2013 and October 2013 respectively. These intercompany loans were back to back with an external debt facility Seadrill had used to finance the construction of the T-15 and T-16. In August 2017, we amended the terms of these loans so that we held the facility directly with the external lender.

We were required to make amortization payments of $19.8 million per year against this facility. We made a prepayment of $15.8 million in August 2017 when we amended the facility and paid further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The Tender Rig facility included a "satisfactory drilling contract" covenant. As a consequence of the T-16 and T-15 not having a satisfactory drilling contract for a period of time, the facility became due on a pro rata basis. In November 2019 there was an early repayment of the entirety of the T-16 balance of $20.0 million. The remaining $2.7 million and $15.9 million balloon payments related to the T-15 were repaid in March and April 2020 respectively. We paid interest on these loans at LIBOR plus a margin of 4.25%.

Presentation in Consolidated Balance Sheets

We present external debt net of debt issuance costs. The below tables show how the above balances are presented in the Consolidated Balance Sheets:

	Outstanding debt as at December 31, 2020
(In $ millions)	Principal outstanding	Debt Issuance Costs (1)	Total Debt
Debt held as subject to compromise	2,727.1	—	2,727.1
Total interest-bearing debt	2,727.1	—	2,727.1

	Outstanding debt as at December 31, 2019
(In $ millions)	Principal outstanding	Debt Issuance Costs	Total Debt
Debt due within twelve months	313.3	(11.9)	301.4
Long-term external debt	2,578.8	(2.0)	2,576.8
Total interest-bearing debt	2,892.1	(13.9)	2,878.2

(1) On filing for Chapter 11 on December 1, 2020 all unamortized debt issuance costs on under secured debt have been written off to "reorganization items, net" in our Consolidated Statement of Operations. For further details refer to Note 4 - "Chapter 11 Proceedings".

Note 17 – Other liabilities

Other liabilities are comprised of the following: 

(In $ millions)	2020	2019
Uncertain tax position	44.4	44.2
Accrued expenses	13.1	34.0
Taxes payable	31.8	35.1
Interest rate swap agreements (1)	—	17.7
Employee and business withheld taxes, social security and vacation payment	8.3	9.0
VAT payable	2.2	4.7
Deferred mobilization/demobilization revenues (see Note 6 - "Revenue from contracts with customers")	0.9	3.0
Total other liabilities (2)	100.7	147.7

Other liabilities are classified in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Other current liabilities	56.3	103.5
Other non-current liabilities	44.4	44.2
Total other liabilities (1)	100.7	147.7

(1) In preparation for Chapter 11 filing, a decision was made to default on the interest rate swap payments that were due on November 23, 2020. As a result, the outstanding derivative balance on this date was held at the counterparty claimed value within "liabilities subject to compromise" on our Consolidated Balance Sheets as at December 31, 2020. Refer to Note 20 - "Risk management and financial instruments" for more information.

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(2) Balances held as at December 31, 2020 exclude liabilities that are subject to compromise, which have been reclassified to a separate line within the Consolidated Balance Sheet. This represents our estimate of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. For further information refer to Note 1 - "General information".

Note 18 - Non-controlling interest

Changes in non-controlling interests for the periods presented in this report were as follows:

(In $ millions)	Non-controlling interest
December 31, 2018	1,384.5
Share of net loss allocated to the non-controlling interest	(94.3)
Cash distributions	(1.5)
December 31, 2019	1,288.7
Share of net loss allocated to the non-controlling interest	(2,038.0)
December 31, 2020	(749.3)

Our non-controlling interest consists of Seadrill Limited's 42% interest in Seadrill Operating LP and 49% interest in Seadrill Capricorn Holdings LLC. Of which, we hold the following:

(1) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Capricorn Holdings LLC owns 100% of the entities that own and operate the West Capricorn, West Sirius, West Auriga and West Vela.

(2) a 58% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through our 100% ownership of its general partner, Seadrill Operating GP LLC. Seadrill Operating LP owns: (a) 100% interest in the entities that own the West Aquarius, West Leo, West Polaris and the West Vencedor, (b) approximately 56% interest in Seadrill Deepwater Drillship that owns and operates the West Capella and (c) a 51% limited liability interest in Seadrill Mobile Units (Nigeria).

Note 19 – Related party transactions

The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2020, 2019 and 2018.

(In $ millions)	2020	2019	2018
Related party inventory sales (a)	1.1	1.8	3.2
Rig operating costs (b)	—	—	1.4
Total related party operating revenues	1.1	1.8	4.6
Management and technical support fees (c) (d)	60.1	70.5	70.6
Rig operating costs (e)	—	—	0.8
Related party inventory purchases (a)	1.4	1.1	0.7
Total related party operating expenses	61.5	71.6	72.1
Interest expense recognized on deferred contingent consideration (h)	(2.0)	(3.3)	(3.1)
Related party interest expense (f)	—	—	(1.4)
Total related party financial items	(2.0)	(3.3)	(4.5)

The below table provides a summary of amounts due to or from Seadrill at December 31, 2020 and December 31, 2019.

(In $ millions)	2020	2019
Trading balances due from Seadrill and subsidiaries (g)	7.6	6.9
Total related party receivables	7.6	6.9

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(In $ millions)	2020	2019
Trading balances due to Seadrill and subsidiaries (g)	78.9	79.5
Deferred and contingent consideration to related party - short term portion (h)	2.8	31.5
Total related party payables	81.7	111.0
Less: Related party payables held as subject to compromise	(74.3)	—
Related party payables not subject to compromise	7.4	111.0

Chapter 11 proceedings

On filing for Chapter 11, our pre-petition related party payables are held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings" of our Consolidated Financial Statements included herein.

(a) Related party inventory sales and purchases

Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.

(b) Rig operating costs charged to Seadrill

Seadrill Partners has charged to Seadrill Limited, through its Nigerian service company, certain services including the provision of onshore and offshore personnel, which was provided for the West Jupiter drilling rig operating in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended in 2018.

(c) Management and administrative services agreement

Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged an allocation for these services on a cost plus mark-up basis. During the year ended December 31, 2020, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreements for certain rigs have been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(d) Operations and technical supervision agreements

In addition, certain subsidiaries of Seadrill Partners have advisory, technical and/or administrative services agreements with subsidiaries of Seadrill. An allocation of these services are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services. This agreements has been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(e) Rig operating costs charged by Seadrill

Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged an allocation for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%.

(f) Interest expense charged by Seadrill

Interest expense charged by Seadrill for the West Vencedor loan arrangement that was due to Seadrill. The loan was repaid during 2018.

(g) Trading balances

Receivables and payables with Seadrill Limited and its subsidiaries are comprised of management fees, advisory and administrative services, and certain other amounts due. Receivables and payables are generally settled quarterly in arrears for those balances that are not held as liabilities subject to compromise. Trading balances to Seadrill Partners and its subsidiaries are unsecured.

(h) Deferred consideration to related party

We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela remaining which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020.

On the West Vela we are required to pay to Seadrill $42k per day for mobilization and a further $40k per day adjusted for utilization over the remaining contract term with BP, which completed in November 2020.

On the West Polaris we agreed to pay Seadrill 100% of dayrate earned above $450k per day for the remainder of the contract with ExxonMobil and 50% of the dayrate earned above $450k per day on any subsequent contract until March 2025. In the year ended December 31, 2019, following reductions in future dayrate estimates and re-contracting assumptions, we impaired the remaining value of the liability to a nil carrying value, resulting in a $0.7 million gain in the Consolidated Statement of Operations.

The below table sets out the fair value of the liabilities at December 31, 2020 and December 31, 2019.

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(In $ millions)	2020	2019
West Vela
Mobilization due to Seadrill	2.8	17.2
Seadrill share of dayrate from BP contract	—	14.3
Total	2.8	31.5

These liabilities are presented in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Current deferred and contingent consideration to related party	—	31.5
Liabilities subject to compromise	2.8	—
Total	2.8	31.5

Other agreements and transactions with Seadrill

Equity Distribution

During the year ended December 31, 2018, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions.

A total cash distribution of $6.2 million has been distributed to Seadrill in the year ended December 31, 2018.

These transactions were presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2018.

Spare parts agreement with Seadrill

During the year ended December 31, 2015, we entered an agreement with Seadrill to store spare parts of the West Sirius rig while it was cold stacked. Seadrill may use the spare parts during the stacking period, but must replace them at its own cost when the West Sirius returns to operations.

Guarantees

Seadrill provided performance guarantees to certain of our customers on our behalf for contracts that matured in 2020. These totaled nil as at December 31, 2020 (December 31, 2019: $15 million).

Omnibus agreement

In 2012 we entered into an Omnibus Agreement with Seadrill Limited. The agreement outlines the following provisions: (i) a non-competition agreement with Seadrill for any drilling rig operating under a contract for five or more years; (ii) rights of first offer on any proposed sale, transfer or other disposition of drilling rigs; (iii) rights of first offer on any proposed transfer, assignment, sale or other disposition of any equity interest in Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC (the "OPCO"); and (iv) indemnification – Old Seadrill Limited agreed to indemnify Seadrill Partners against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to Seadrill Partners, and also certain tax liabilities.

Note 20 – Risk management and financial instruments

We are exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. We may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.

Due to the filing of the Bankruptcy Petitions, interest is no longer incurred on our debt facilities. Prior to filing for Chapter 11, we entered into a derivative agreement to mitigate the risk of interest rate fluctuations. We defaulted on payments due on the interest rate swaps on November 23, 2020 in preparation for the Chapter 11 filing.

As a result, our counterparties terminated all outstanding transactions governed by the International Swaps and Derivatives Association, Inc. ("ISDA"). The derivative transactions are recognized at the recoverable amount under the ISDA's as agreed with our lenders. As at December 31, 2020 we had $20.8 million in estimated derivative instrument settlements payable, reflected as "liabilities subject to compromise" in our Consolidated Balance Sheets.

Interest rate risk management

Our exposure to interest rate risk relates mainly to our floating interest rate debt and balances of surplus funds placed with financial institutions. The exposure related to our floating interest debt has reduced since filing for Chapter 11 as interest is no longer incurred on our debt facilities. Our objective is to obtain the most favorable interest rate borrowings available without increasing its exposure to fluctuating interest rates. Surplus funds are used to repay revolving credit tranches or placed in accounts and deposits with reputable financial institutions in order to maximize returns, while providing us with flexibility to meet all requirements for working capital and capital investments. The extent to which we utilize interest rate swaps to manage our interest rate risk is determined by our net debt exposure and our views on future interest rates.

F- 27

Interest rate swap agreements

As at November 23, 2020, we had interest rate swaps for a combined outstanding principal amount of $2,714.1 million, (December 31, 2019: $2,735.8 million) swapping floating rate for an average fixed rate of 2.49% per annum. The fair value of the interest rate swaps outstanding as of December 31, 2020 was a liability of $20.8 million (December 31, 2019: liability of $17.7 million). The collateral vessels under our TLB have been pledged as collateral against our interest rate swap liabilities. The interest rate swaps are secured on a pari passu basis with the TLB lenders. The swap providers rank lower on the payment waterfall with regards to the super senior loan.

We record interest rate swaps on a net basis where netting is allowed under ISDA Master Agreements. We classify the net asset or liability within other current assets or current liabilities. We have not designated any interest swaps as hedges and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statements of Operations under "loss/gain on derivative financial instruments".

On December 1, 2020, the interest rate swaps were terminated under the ISDA and an adjustment for credit risk on the interest rate swap position was reversed to "other financial expenses" in the Consolidated Statement of Operations, totaling $7.1 million. The residual liability represents the counterparty claimed value of $20.8 million, which was reclassified to "liabilities subject to compromise" in our Consolidated Balance Sheets as at December 31, 2020.

The total realized and unrealized loss recognized under "loss/gain on derivative financial instruments" in the Consolidated Statements of Operations relating to interest rate swap agreements for 2020 was a loss of $16.1 million (2019: loss of $27.7 million, 2018: gain of $24.9 million).

Our interest rate swap agreements as at November 23, 2020, were as follows:

Maturity date	Outstanding principal as at November 23, 2020		Receive rate	Pay rate
	(In $ millions)
February 21, 2021	2,714.1		3 month LIBOR	2.45% to 2.52%	(1) (2)
Total outstanding principal	$	2,714.1

(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.

(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.

Following the defaults on our debt and the termination of our derivatives in 2020 we no longer have any net exposure to short term fluctuations in interest rates. As at December 31, 2019, $156.3 million of our debt was exposed to interest rate fluctuations.

The credit exposure of interest rate swap agreements is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements, adjusted for counterparty non-performance credit risk assumptions. It is our policy to enter into ISDA Master Agreements, with the counterparties to derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes us.

Foreign currency risk

We use the U.S. Dollar as the functional currency of all our subsidiaries because the majority of our revenues and expenses are denominated in U.S. Dollars. Therefore, we also use U.S. Dollars as our reporting currency.

Our foreign currency risk arises from:

•the measurement of monetary assets and liabilities denominated in foreign currencies converted to U.S. Dollars, with the resulting gain or loss recorded as "currency exchange loss/gain"; and

•the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies.

We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.

Credit risk

We have financial assets which expose us to credit risk arising from possible default by a counterparty. Our counterparties primarily include our customers, which are international oil companies, national oil companies or large independent companies or financial institutions. We consider these counterparties to be creditworthy and do not expect any significant loss due to credit risk. We don't demand collateral from our counterparties in the normal course of business. Credit risk is also considered as part of our expected credit loss provision. Refer to Note 2 - "Accounting policies" for further information.

Concentration of Credit Risk

There is a concentration of credit risk with respect to revenue as one of our customers represent more than 10% of total revenues. Refer to Note 5 - "Segment information" for an analysis of our revenue by customer. The market for our services is the offshore oil and gas industry, and our customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral from them. Reserves for potential credit losses are maintained when necessary.

F- 28

There is a concentration of credit risk with respect to cash and cash equivalents as most of the amounts are deposited with Nordea Bank Finland Plc and Danske Bank A/S. We consider these risks to be remote given the investment grade credit rating of these banks.

Note 21 – Fair Value Measurement

Fair value of financial assets and liabilities measured at amortized cost

The carrying value and estimated fair value of our financial instruments that are measured at amortized cost as of December 31, 2020 and December 31, 2019 are as follows:

	2020		2019
(In $ millions)	Fair Value	Carrying  Value	Fair Value	Carrying  Value
Assets
Cash and cash equivalents	362.0	362.0	560.0	560.0
Restricted cash	16.4	16.4	—	—
Liabilities
Term Loan B	380.3	2,727.1	1,300.5	2,595.9
Other external debt facilities	—	—	269.7	282.3

Level 1

The carrying value of cash and cash equivalents and restricted cash, which are highly liquid, is a reasonable estimate of fair value.

As at December 31, 2020, we had loans under the Term Loan B with a carrying value of $2,727.1 million, all of which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets. As at December 31, 2020 and as at December 31, 2019 the Term B loan was freely tradable and its fair value was set equal to the price at which they were traded on this date.

Level 2

Loans under other external debt facilities relate to the West Vela facility (previously the $1,450 million Senior Secured Credit Facility), West Polaris facility, Tender Rig facility (previously the $440 million Rig Financing Agreement) and the West Vencedor facility. These loans are not freely tradable.

The debt facilities were fully repaid in 2020 and not included in the table above for year ending December 31, 2020. For the year ended December 31, 2019 the fair value was determined using of the current and long-term portion of these debt facilities was derived using a discounted cash flow model, using a cost of debt of 11.16%, with reference to the expected contractual repayments under the agreements. Refer to Note 16 - "Debt" for further information.

Financial instruments measured at fair value on a recurring basis

As at December 31, 2019, the fair values of interest rate swap contracts of $17.7 million were calculated using well-established independent valuation techniques, applied to contracted cash flows and expected future LIBOR interest rates, and counterparty non-performance credit risk assumptions as that date. The calculation of the credit risk in the swap values were subject to a number of assumptions including an assumed Credit Default Swap rate based on the Company's traded debt, plus a curve profile and recovery rate. These items were level 2 on the fair value hierarchy.

In 2019, the fair value of the related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris of $31.5 million was estimated based on discounted future cash flows. These liabilities were considered to be at estimated market rates. These have been categorized at level 2 on the fair value measurement hierarchy.

As at December 31, 2020, we had $20.8 million of interest rate swaps and $2.8 million of related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris, all of which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets at the expected value of the allowable claim. The interest rate swaps balance reflects the terminated value as at November 23, 2020 following the decision that was made to default on payments in preparation for Chapter 11 filing. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings".

F- 29

Fair value considerations on non-recurring transactions

Certain of our assets and liabilities are required to be measured at fair value on a nonrecurring basis in accordance with U.S. GAAP. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. Refer to Note 10 - "Impairment of long-lived assets" for details of impairment charges relating to our drilling units, which were measured at fair value on a nonrecurring basis in 2020 and have presented the aggregate loss in “Impairment of long-lived assets” in our Consolidated Statements of Operations for the year ended December 31, 2020.

The assets measured at estimated fair value as of December 31, 2020 are as follows:

	2020
(In $ millions)	Fair Value	Carrying  Value
Assets
Drilling units	428.3	428.3

Level 3

The drilling units were impaired during the first and fourth quarters of 2020. We estimated the fair values of the impaired drilling units using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. These calculations utilized significant unobservable inputs, including management’s assumptions related to long-term future dayrates, contract probabilities, long-term economic utilization, capital and operating expenditures, reactivation costs and timing for the cold stacked rigs, recycling probabilities, applicable tax rates and asset lives. Our fair value estimates were representative of Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used.

Note 22 –Commitments and contingencies

Legal Proceedings

From time to time the Company is a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with its acquisition or disposal activities. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2020.

West Leo

We received notification of a force majeure occurrence on October 1, 2016 in respect of the West Leo which was operating for Tullow Ghana Limited ("Tullow") in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience. We did not accept that the contract had been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract had been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this.

On July 3, 2018 the English High Court ruled the case in our favor and we recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "other revenues" per our Consolidated Statements of Operations. See Note 8 - "Other revenues" for further details.

Patent infringement

In January 2015, a subsidiary of Transocean Ltd. filed suit (the "Suit") against certain of our subsidiaries for patent infringement. The Suit alleged that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.

In December 2018, we reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean for the dual activity drilling method on our rigs covering alleged past infringements and future use.

BP arbitration

In 2019, an arbitration entitled Seadrill US Gulf LLC, Seadrill Gulf Operations Vela LLC, and Seadrill Gulf Operations Auriga, LLC v. BP Exploration & Production, Inc., ICDR Case No. 01-19-003-0191 (the “Arbitration”), which was commenced by Seadrill US Gulf LLC, Seadrill Gulf Operations Vela, LLC, and Seadrill Gulf Operations Auriga LLC (collectively, the “Arbitration Debtors”) against BP Exploration & Production, Inc. (“BP”) and is currently pending before a three-arbitrator tribunal appointed by the International Centre for Dispute Resolution (the “Tribunal”), an affiliate of the American Arbitration Association (“AAA”). The Arbitration involves breach of contract claims against BP. BP has not asserted any counterclaims against the Arbitration Debtors.

F- 30

The Arbitration Debtors and BP are parties to long-term contracts (the “Contracts”) worth $4.4 billion under which the Arbitration Debtors provided drilling rigs to BP. The Arbitration involves a dispute over the meaning of change-in-law provisions contained in the Contracts (the “Change-in-Law Provisions”). The Arbitration Debtors seek a total of $51 million for BP’s refusal to fully compensate their increased U.S. federal income tax costs incurred pursuant to the 2017 enactment of a Base Erosion Anti-Abuse Tax (“BEAT”).

Base erosion and anti-abuse tax (BEAT)

We continue to recognize income tax expense related to a provision of the 2017 US tax reform commonly referred to as BEAT. Three US drilling contracts include a change in legislation provision we believe makes the BEAT liability reimbursable. In September 2019 the Seadrill contracting parties commenced arbitration proceedings in New York for all three rigs to enforce these contractual obligations. A final hearing in the arbitration was held in March 2021 and a decision from the arbitration panel is expected in the first half of 2021.

Nigerian Cabotage Act litigation

Seadrill Mobile Units Nigeria Ltd ("SMUNL") commenced proceedings in May 2016 against the Honourable Minister for Transportation, the Attorney General of the Federation and the Nigerian Maritime Administration and Safety Agency with respect to interpretation of the Coastal and Inland Shipping (Cabotage) Act 2003 (the "Act"). On June 28, 2019, the Federal High Court of Nigeria delivered a judgement finding that: (1) Drilling operations fall within the definition of "Coastal Trade" or "Cabotage" under the Act and (2) Drilling Rigs fall within the definition of "Vessels" under the Act. The impact of this decision is that the Nigerian Maritime Administration and Safety Agency ("NIMASA") may impose a 2% surcharge on contract revenue from offshore drilling operations in Nigeria as well as requiring SMUNL register for Cabotage with NIMASA and pay all fees and tariffs as may be published in the guidelines that may be issued by the Minister of Transportation in accordance with the Act. However, on 22 July, 2019, SMUNL filed an appeal to the Court of Appeal challenging the decision of the Federal High Court. Due to the volume of cases currently being handled by the Court of Appeal sitting in Lagos we anticipate a decision within three to five years.

Although we intend to strongly pursue this appeal, we cannot predict the outcome of this case. We do not believe that it is probable that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. Accordingly, no loss contingency has been recognized within the Consolidated Financial Statements.

Other claims or legal proceedings

We are not aware of any other legal proceedings or claims that we expect to have, individually or in the aggregate, a material adverse effect on the Company.

Commitments

We had no material lease commitments or unconditional purchase obligations at December 31, 2020 and 2019.

Guarantees

We have issued performance guarantees under our bank guarantee facility with Danske Bank in favor of third parties as beneficiaries totaling $11.9 million. As of December 31, 2020 we have not recognized any liabilities for these guarantees, as we do not consider it is probable for the guarantees to be called.

F- 31

Note 23 – Earnings per unit and cash distributions

The below table sets out the calculation of (loss)/earnings per unit for each of periods presented in this report.

(in $ millions, except per unit data)	2020		2019		2018
Net (loss)/income attributable to:
Common unitholders	(2,091.3)		(76.2)		56.1
Subordinated unitholders	(459.6)		(16.7)		—
Net (loss)/income attributable to Seadrill Partners LLC owners	(2,550.9)		(92.9)		56.1
Weighted average units outstanding (in thousands):
Common unitholders	7,528		7,528		7,528		*
Subordinated unitholders	1,654		1,654		1,654		*
(Loss)/Earnings per unit:
Common unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	$	7.45	*
Subordinated unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	—
Cash distributions declared and paid in the period per unit (1) (2)	$	—	$	0.22	$	4.00	*
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):	$	—	$	—	$	0.01	*

* These amounts have been updated to reflect the 1 for 10 reverse stock split on July 2, 2019.

(1) Refers to the cash distributions declared and paid during the prior years.

(2) Distributions were declared and paid only with respect to the common units in 2019 and 2018.

(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.

Earnings per unit is calculated using the two-class method where undistributed earnings are allocated to the various member interests. The net income attributable to the common and subordinated unitholders and the holders of the incentive distribution rights is calculated as if all net income was distributed according to the terms of the distribution guidelines set forth in the Operating Agreement, regardless of whether those earnings could be distributed. The Operating Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of the quarter after establishment of cash reserves determined by the Company's Board of Directors to provide for the proper conduct of the Company's business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Therefore, the earnings per unit is not indicative of potential cash distributions that may be made based on historic or future earnings. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains/(losses).

Under the Operating Agreement, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $3.8750 per unit per quarter, plus any arrearages in the payment of minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

Distributions of available cash from operating surplus are to be made in the following manner for any quarter during the subordination period:

•First, to the common unitholders, pro-rata, until the Company distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•Second, to the common unitholders, pro-rata, until the Company distributes for each outstanding common an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters during the subordination period; and

•Third, to the subordinated units, pro-rata, the Company distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.

F- 32

In addition, the Seadrill Member currently holds all of the incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of the quarterly distributions of cash available from operating surplus after the minimum quarterly distribution and target distribution levels have been achieved.

If for any quarter during the subordination period:

•The Company has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•The Company has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

The Company will then distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of the incentive distributions rights in the following manner:

•first, 100.0% to all unitholders, until each unitholder receives a total of $4.456 per unit for that quarter (the "first target distribution");

•second, 85.0% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $4.844 per unit for that quarter (the "second target distribution");

•third, 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $5.813 per unit for that quarter (the "third target distribution"); and

•thereafter, 50.0% to all unitholders, and 50.0% to the holders of the incentive distribution rights, pro rata.

The percentage interests set forth above assumes that the Company does not issue additional classes of equity securities.

The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:

•distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•the "adjusted operating surplus" (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and

•there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.

In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by the conflicts committee, the holder or holders of a majority of the subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.

Note 24 - Supplementary cash flow information

The table below summarizes the non-cash investing and financing activities relating to the periods presented:

(In $ millions)	2020	2019	2018
Non-cash financing activities
Recognition of super senior loan and related fees (1)	141.5	—	—
Reclassification of prepaid advisory fees (2)	19.8	—	—

(1) In the year ended December 31, 2020, unpaid TLB interest of $87 million was converted into a super senior loan, carrying a $40 million commitment fee, $13.3 million exit fee and $1.2 million compounded interest. For more information refer to Note 16 – "Debt".

(2) $19.8 million prepaid refinancing advisory fees incurred up until July 2020 were reclassified from prepaid expenses to loan fees.

F- 33

Note 25 – Subsequent events

Management Agreements

On February 3, 2021 the Company entered into a management agreement with Energy Drilling to maintain, market and operate our owned tender rigs T-15, T-16, and West Vencedor. The agreement started a 90-day transition period of services provided from Seadrill Limited to Energy Drilling.

On February 10, 2021 the Company submitted a motion for approval of a new framework agreement with Vantage Drilling for the management of certain rigs in our fleet. Following the execution of the Vantage Drilling management services agreement, the Debtors continued to receive proposals with respect to the operation of their floater vessels. Because the Vantage Drilling management services agreement remained subject to Bankruptcy Court approval (and was therefore not binding upon the Debtors), the Debtors undertook to assess such alternative proposals. Upon assessing the alternative proposals, the Debtors determined that the commercial proposition served by using a combination of Vantage Drilling, Diamond Offshore Drilling Inc. (“Diamond”), and Odfjell Drilling Ltd. (“Odjfell”), each as managers of certain of the Debtors’ floater vessels, was superior to the original Vantage Drilling management structure. Therefore, on March 16, 2021, the Debtors filed a supplement to the motion seeking approval of management services agreements with Vantage Drilling, Diamond, and Odjfell. On March 18, 2021, the Bankruptcy Court approved the motion, authorizing the Debtors to enter into management services agreements with Diamond, Odfjell, and an amended management services agreement with Vantage Drilling.

F- 34

EX-8.1

EXHIBIT 8.1

Subsidiaries of the Company

The following table lists the Company’s significant subsidiaries and their purpose that are included in the Consolidated Financial Statements as of December 31, 2020.

Name of the Company	Jurisdiction of  Incorporation	Principal Activities
Seabras Rig Holdco Kft	Hungary	Rig owner
Seadrill Auriga Hungary Kft	Hungary	Rig owner
Seadrill Canada Ltd	Canada	Operating company
Seadrill Capricorn Holdings LLC	Marshall Islands	Holding company
Seadrill China Operations Ltd	Luxembourg	Rig owner
Seadrill Deepwater Drillship Ltd	Cayman Islands	Rig owner
Seadrill Ghana Operations Ltd	Bermuda	Operating company
Seadrill Gulf Operations Auriga LLC	U.S.A.	Operating company
Seadrill Gulf Operations Sirius LLC	U.S.A.	Operating company
Seadrill Gulf Operations Vela LLC	U.S.A.	Operating company
Seadrill Hungary Kft	Hungary	Rig owner
Seadrill International Ltd	Hong Kong	Operating company
Seadrill Leo Ltd	Bermuda	Rig owner
Seadrill Mobile Units Ltd	Nigeria	Service company
Seadrill Operating LP	Marshall Islands	Holding company
Seadrill Operating GP LLC	Marshall Islands	Holding company
Seadrill Operating LLC	Marshall Islands	Holding company
Seadrill Partners Malaysia Sdn Bhd	Malaysia	Operating company
Seadrill Partners Operating LLC	Marshall Islands	Holding company
Seadrill Polaris Ltd.	Bermuda	Rig Owner
Seadrill T15 Ltd	Bermuda	Rig owner
Seadrill T16 Ltd	Bermuda	Rig owner
Seadrill US Gulf LLC	U.S.A.	Operating company
Seadrill Vela Hungary Kft	Hungary	Rig owner
Seadrill Vencedor Ltd	Bermuda	Rig owner

EX-12.1

EXHIBIT 12.1

CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

I, John T. Roche, certify that:

1. I have reviewed this annual report on Form 20-F of Seadrill Partners LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and

5. The company's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting.

Date: April 30, 2021

/s/ John T. Roche

John T. Roche

Chief Executive Officer and Chief Financial Officer of Seadrill Partners LLC

(Principal Executive Officer of Seadrill Partners LLC)

EX-13.1

EXHIBIT 13.1

PRINCIPAL EXECUTIVE OFFICER CERTIFICATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Annual Report of Seadrill Partners LLC (the "Company") on Form 20-F for the year ended December 31, 2020 as filed with the Securities and Exchange Commission (the "SEC") on or about the date hereof (the "Report"), I, John T. Roche, Principal Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement has been provided to the Company and will be retained by the Company and furnished to the SEC or its staff upon request.

Date: April 30, 2021

/s/ John T. Roche

John T. Roche

Chief Executive Officer and Chief Financial Officer of Seadrill Partners LLC

(Principal Executive Officer of Seadrill Partners LLC)

EX-15.1

EXHIBIT 15.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form F-3 (No. 333-192053) of Seadrill Partners LLC of our report dated April 30, 2021 relating to the financial statements, which appear in this Form 20-F.

/s/ PricewaterhouseCoopers LLP

Watford, United Kingdom

April 30, 2021

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	Dec. 31, 2020 shares
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Current Fiscal Year End Date	--12-31
Document Transition Report	false
Document Shell Company Report	false
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Entity Registrant Name	SEADRILL PARTNERS LLC
Entity Incorporation, State or Country Code	1T
Entity Address, Address Line One	2nd floor, Building 11
Entity Address, Address Line Two	Chiswick Business Park
Entity Address, Address Line Three	566 Chiswick High Road
Entity Address, City or Town	London
Entity Address, Postal Zip Code	W4 5YS
Entity Address, Country	GB
Contact Personnel Email Address	post@seadrill.com
Entity Common Stock, Shares Outstanding (in shares)	7,527,830
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
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Document Information [Line Items]
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Entity Address, Address Line One	2nd floor, Building 11
Entity Address, Address Line Two	Chiswick Business Park
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Entity Common Stock, Shares Outstanding (in shares)	1,654,335

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues
Contract revenues		$ 525.9	$ 686.5	$ 797.5
Total operating revenues		538.1	750.0	1,038.2
Operating expenses
Depreciation		(230.8)	(275.9)	(280.3)
Amortization of favorable contracts		(40.4)	(45.1)	(45.1)
Selling, general and administrative expenses	[1]	(34.4)	(34.4)	(45.8)
Total operating expenses		(571.7)	(700.1)	(678.0)
Other operating items
Loss on impairment of goodwill		0.0	0.0	(3.2)
Revaluation of contingent consideration		0.0	0.7	0.0
Impairment of long-lived assets		(4,210.4)	0.0	0.0
Total other operating items		(4,210.4)	0.7	(3.2)
Operating (loss)/income		(4,244.0)	50.6	357.0
Financial items
Interest income		6.1	20.3	47.1
Interest expense	[1]	(235.3)	(262.5)	(263.7)
(Loss)/gain on derivative financial instruments	[1]	(16.1)	(27.7)	24.9
Currency exchange (loss)/gain		(2.7)	(2.6)	0.2
Reorganization items, net		(49.8)	0.0	0.0
Other financial expenses		(17.1)	(1.4)	(4.8)
Total financial items		(314.9)	(273.9)	(196.3)
(Loss)/income before income taxes		(4,558.9)	(223.3)	160.7
Income tax (expense)/benefit		(30.0)	36.1	(86.7)
Net (loss)/income		(4,588.9)	(187.2)	74.0
Net (loss)/income attributable to Seadrill Partners LLC members		(2,550.9)	(92.9)	56.1
Net (loss)/income attributable to the non-controlling interest		$ (2,038.0)	$ (94.3)	$ 17.9
(Loss)/Earnings per unit (common and subordinated)
Common unitholders (basic and diluted) (in usd per share)		$ (277.80)	$ (10.12)	$ 7.45
Subordinated unitholders (basic and diluted) (in usd per share)		$ (277.80)	$ (10.12)	$ 0
Reimbursable revenues/expenses
Operating revenues
Reimbursable and other revenues		$ 11.1	$ 20.7	$ 31.2
Operating expenses
Expenses		(10.2)	(19.4)	(28.6)
Other revenues
Operating revenues
Reimbursable and other revenues	[1]	1.1	42.8	209.5
Vessel and rig operating expenses
Operating expenses
Expenses	[1]	$ (255.9)	$ (325.3)	$ (278.2)

[1] Includes transactions with related parties. Refer to Note 19 - "Related party transactions".

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 362.0	$ 560.0
Restricted cash	16.4	0.0
Accounts receivable, net	56.6	146.7
Amount due from related party	7.6	6.9
Other current assets	45.0	119.5
Total current assets	487.6	833.1
Non-current assets
Drilling units	428.3	4,840.8
Deferred tax assets	3.3	6.1
Other non-current assets	8.0	0.0
Total non-current assets	439.6	4,846.9
Total assets	927.2	5,680.0
Current liabilities
Debt due within twelve months	0.0	301.4
Trade accounts payable and accruals	4.2	17.4
Current portion of deferred and contingent consideration to related party	0.0	31.5
Related party payable	7.4	79.5
Other current liabilities	56.3	103.5
Total current liabilities	67.9	533.3
Liabilities subject to compromise	2,879.1	0.0
Non-current liabilities
Long-term debt	0.0	2,576.8
Deferred tax liability	1.0	2.0
Other non-current liabilities	44.4	44.2
Total non-current liabilities	45.4	2,623.0
Commitments and contingencies (see Note 22)
Members' Capital:
Common unitholders (issued 7,527,830 units as at December 31, 2020 and December 31, 2019)	(944.5)	1,146.8
Subordinated unitholders (issued 1,654,335 units as at December 31, 2020 and December 31, 2019)	(371.4)	88.2
Total members' capital	(1,315.9)	1,235.0
Non-controlling interest	(749.3)	1,288.7
Total (deficit)/equity	(2,065.2)	2,523.7
Total liabilities and equity	$ 927.2	$ 5,680.0

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CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - shares	Dec. 31, 2020	Dec. 31, 2019
Equity
Common units issued (in units)	7,527,830	7,527,830
Subordinated units issued (in units)	1,654,335	1,654,335

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Flows from Operating Activities
Net (loss)/income	$ (4,588.9)	$ (187.2)	$ 74.0
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Depreciation	230.8	275.9	280.3
Amortization of deferred loan charges	44.2	11.7	12.4
Amortization of favorable contracts	40.4	45.1	45.1
Impairment of long-lived assets	4,210.4	0.0	0.0
Loss on impairment of goodwill	0.0	0.0	3.2
Unrealized (gain)/loss related to derivative financial instruments	(4.0)	27.6	(38.9)
Payment for long term maintenance	(19.3)	(81.4)	(91.6)
Non-cash reorganization items	42.9	0.0	0.0
Reversal of credit risk on derivatives	7.1	0.0	0.0
Deferred tax expense	1.7	3.2	0.7
Gain on revaluation of contingent consideration	0.0	(0.7)	0.0
Accretion of discount on deferred consideration	1.9	3.2	5.3
Changes in operating assets and liabilities, net of effect of acquisitions
Trade accounts receivable	90.1	4.2	103.2
Prepaid expenses and accrued income	(32.4)	(2.0)	(3.6)
Trade accounts payable	0.1	(8.3)	(11.2)
Related party balances	(1.3)	(47.3)	(12.9)
Other assets	38.7	0.7	15.5
Other liabilities	104.7	(69.4)	56.5
Changes in deferred revenue	(2.1)	(1.3)	(3.4)
Other, net	0.0	0.0	(0.5)
Net cash provided by/(used in) operating activities	165.0	(26.0)	434.1
Cash Flows from Investing Activities
Additions to drilling units	(9.4)	(29.7)	(23.4)
Net cash used in investing activities	(9.4)	(29.7)	(23.4)
Cash Flows from Financing Activities
Repayments of debt	(306.6)	(192.6)	(296.4)
Repayments of related party debt	0.0	0.0	(24.7)
Contingent consideration paid	(30.6)	(30.0)	(34.0)
Cash distributions	0.0	(3.3)	(55.4)
Repayment of shareholder loan	0.0	0.0	(6.2)
Net cash used in financing activities	(337.2)	(225.9)	(416.7)
Effect of exchange rate changes on cash	0.0	0.0	(1.0)
Net decrease in cash and cash equivalents	(181.6)	(281.6)	(7.0)
Cash and cash equivalents at beginning of the year	560.0	841.6	848.6
Cash and cash equivalents, including restricted cash, at the end of year	378.4	560.0	841.6
Supplementary disclosure of cash flow information
Interest and other financial items paid	68.9	247.6	261.3
Taxes paid	$ 21.7	$ 50.1	$ 24.9

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CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS' CAPITAL - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Partners' Capital [Roll Forward]
Consolidated balance, beginning of period	$ 2,523.7	$ 2,714.2	$ 2,701.8
Net (loss)/income	(4,588.9)	(187.2)	74.0
Cash distributions		(3.3)	(55.4)
Cash distributions		(1.5)
Repayment of shareholder loan	0.0	0.0	(6.2)
Consolidated balance, end of period	(2,065.2)	2,523.7	2,714.2
Total Before Non- controlling interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Consolidated balance, beginning of period	1,235.0	1,329.7	1,303.7
Net (loss)/income	(2,550.9)	(92.9)	56.1
Cash distributions		(1.8)	(30.1)
Consolidated balance, end of period	(1,315.9)	1,235.0	1,329.7
Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Consolidated balance, beginning of period	1,146.8	1,224.8	1,208.9
Net (loss)/income	(2,091.3)	(76.2)	46.0
Cash distributions		(1.8)	(30.1)
Consolidated balance, end of period	(944.5)	1,146.8	1,224.8
Subordinated Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Consolidated balance, beginning of period	88.2	104.9	94.8
Net (loss)/income	(459.6)	(16.7)	10.1
Consolidated balance, end of period	(371.4)	88.2	104.9
Non- controlling interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Consolidated balance, beginning of period	1,288.7	1,384.5	1,398.1
Net (loss)/income	(2,038.0)	(94.3)	17.9
Cash distributions		(1.5)	(25.3)
Repayment of shareholder loan			(6.2)
Consolidated balance, end of period	$ (749.3)	$ 1,288.7	$ 1,384.5

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General information

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General information

General information

Background

Seadrill Partners LLC (the "Company", "we" or "our") is incorporated in the Republic of the Marshall Islands. We provide offshore drilling services to the oil and gas industry. As at December 31, 2020 we owned and operated 11 offshore drilling units. Our fleet consists of drillships, semi-submersible rigs and tender rigs for operations in shallow and deepwater areas, as well as benign and harsh environments.

As of October 24, 2012 we were listed on the New York Stock Exchange ("NYSE"). On December 11, 2019, the NYSE filed a Form 25 with the SEC in connection with the delisting and deregistration of our common units. Delisting of our common units from the NYSE became effective 10 days after the filing date of the Form 25. The Form 25 was filed as part of delisting procedures resulting from the company's low market capitalization, as we previously announced on September 6, 2019. Our common units currently trade on the over-the-counter market ("OTC") under the ticker symbol "SDLPQ".

Chapter 11 proceeding and going concern

Since the mid-2010s, the industry has experienced a sustained decline in oil prices which has culminated in an industry-wide supply and demand imbalance. During this period, market dayrates for drilling rigs have been lower than was anticipated when the debt associated with acquiring our rigs was incurred. This challenging business climate was further destabilized by challenges that have arisen due to the COVID-19 pandemic. The actions taken by governmental authorities around the world to mitigate the spread of COVID-19 have had a significant negative effect on oil consumption. This has led to a further decrease in the demand for our services and has had an adverse impact on our business and financial condition.

On December 1, 2020 Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petition for reorganization under Chapter 11 triggering a stay on enforcement of remedies with respect to our debt obligations. As at December 31, 2020 we had total debt outstanding of $2,727.1 million under our credit facilities, all of which matures in the first quarter of 2021. As part of the Chapter 11 proceedings, the Debtors were granted “first-day” relief which enables us to continue operations without interruption. On February 12, 2021, the Debtors and certain of their prepetition lenders executed a plan support agreement, which contemplates a series of restructuring transactions that will equitize approximately $2.7 billion in secured term loan obligations and select go-forward, value maximizing services providers.

As of December 31, 2020, we had cash and cash equivalents of $378.4 million of which $362 million was unrestricted and we have implemented, and will continue to implement, various measures to preserve liquidity. These include primarily deferrals of capital expenditures and cold stacking the drilling units, as well as an increased focus on operating efficiency and reductions in corporate and overhead expenditures. Whilst we believe this should provide sufficient liquidity for the 12 month period from the issuance of these financial statements to allow us to complete a comprehensive restructuring, the process is difficult to predict and subject to factors outside of our control. We are subject to numerous risks associated with the bankruptcy proceedings and there can be no assurance that we will agree a plan of reorganization that is acceptable to our creditors, nor that the Bankruptcy Court would confirm such a plan once agreed.

These conditions and events raise substantial doubt as to our ability to continue as a going concern for the twelve months after the date our financial statements are issued. Financial information in this report has been prepared on a going concern basis of accounting, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Financial information in this report does not reflect the adjustments to the carrying values of assets, liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material.

Basis of presentation

The Consolidated Financial Statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States Dollars ("U.S. Dollars" or "US$") rounded to the nearest million, unless otherwise stated.

Basis of consolidation

The financial statements include the results and financial position of all companies in which we directly or indirectly hold more than 50% of the voting control. We eliminate all intercompany balances and transactions.

We control Seadrill Operating LP and its majority owned subsidiaries as well as Seadrill Capricorn Holdings LLC and its majority owned subsidiaries. We separately present within equity on our Consolidated Balance Sheets the ownership interests attributable to parties with non-controlling interests in our Consolidated subsidiaries, and we separately present net income attributable to such parties in our Consolidated Statements of Operations.

Bankruptcy accounting

Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petitions on December 1, 2020 (the "Petition Date") to commence prearranged reorganization proceedings under Chapter 11 of Title 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the Southern District of Texas (the “Bankruptcy Court”) case number 20-35740. During the pendency of the

Chapter 11 proceedings, the Debtors will operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provision of the Bankruptcy Code. For further information refer to Note 4 - "Chapter 11 Proceedings".Since the Petition Date, we prepared our Consolidated Financial Statements under Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 requires that the financial statements, for periods subsequent to filing bankruptcy petitions, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net" on the Company’s Consolidated Statements of Operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the Consolidated Balance Sheets, particularly liabilities. Pre-petition obligations that may have been impacted by Chapter 11 reorganization process were classified on the Consolidated Balance Sheets within "Liabilities subject to compromise".

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Accounting policies

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Accounting policies

Accounting policies

The accounting policies set out below have been applied consistently to all periods in these Consolidated Financial Statements, unless otherwise noted.

Allowance for credit losses

We adopted accounting standard update 2016-13 Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The new guidance replaces the “incurred loss” model required under the previous guidance with a current “expected credit loss” (or CECL) model. The CECL model requires recognition of expected credit losses over the life of a financial asset upon its initial recognition. Comparative periods are presented under the previous guidance with an allowance against a receivable balance recognized only if it was probable that we would not recover the full amount due to us. We determined doubtful accounts on a case-by-case basis and considered the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. The CECL model applies to external trade receivables, related party receivables and other financial assets measured at amortized cost. We have determined that on transition and at December 31, 2020, the impact of the CECL model is not material and no credit loss adjustments have been applied.

The CECL model contemplates a broader range of information to estimate expected credit losses over the contractual lifetime of an asset. It also requires to consider the risk of loss even if it is remote. We estimate expected credit losses based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts of events which may affect the collectability. We estimate the CECL allowance using a “probability-of-default” model, calculated by multiplying the exposure at default by the probability of default by the loss given default by a risk overlay multiplier over the life of the financial instrument (as defined by ASU 2016-13).

Revenue from contracts with customers

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract with a customer. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments of service.

We recognize revenues for activities that correspond to a distinct time increment of service within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment of service, ratably over the estimated contract term.

We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required. Refer to Note 6 - "Revenue from contracts with customers".

Dayrate drilling revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment service it relates to. Revenue is recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract. The associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.

Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional

contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as "reimbursable revenues" in our Consolidated Statements of Operations.

Local Taxes - In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.

Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.

Other revenues

Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 8 - ''Other revenues''. Revenue is recognized as the performance obligation is satisfied, which on our leased rigs is on a straight-line basis.

Related party revenues - Related party revenues relate to onshore support and offshore personnel provided to Seadrill.

Early termination fees - Other revenues also include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved. Refer to Note 19 - ''Related party transactions''.

Vessel and rig operating expenses

Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.

Mobilization and demobilization expenses

We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see "Deferred Contract Costs" above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.

We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract.

Repairs, maintenance and periodic surveys

Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.

Income taxes

Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Refer to Note 7 – "Taxation".

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits.

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. We recognize the income tax effects of intercompany sales or

transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period of sale or transfer occurs.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as at the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Foreign currencies

The majority of our revenues and expenses are denominated in U.S. Dollars and therefore the majority of our subsidiaries use U.S. Dollars as their functional currency. Our reporting currency is also U.S. Dollars. For subsidiaries that maintain their accounts in currencies other than U.S. Dollars, we use the current method of translation whereby the Statements of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in members' capital.

Transactions in foreign currencies are translated into U.S. Dollars at the rates of exchange in effect at the date of the transaction. Foreign currency denominated monetary assets and liabilities are remeasured using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the Consolidated Statements of Operations.

Earnings Per Unit ("EPU")

We compute EPU using the two-class method set out in GAAP. We first allocate undistributed earnings for the period to the holders of common units, subordinated units and incentive distribution rights. This allocation is made in accordance with the cash distribution provisions contained in our First Amended and Restated Operating Agreement of the Company (the "Operating Agreement"). Unallocated earnings may be negative if amounts distributed are higher than total earnings. We allocate such deficits using the same cash distribution model.

We calculate the EPU for each category of units by taking the sum of the distributions to those units plus the allocation of those units undistributed earnings for the period and dividing this total by the weighted average number of units outstanding for the period. We don't have any potentially dilutive instruments and therefore don't present a diluted EPU. Refer to Note 23 - ''Earnings per unit and cash distributions''.

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. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets. Hierarchy Level 2 inputs are 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. Hierarchy Level 3 inputs are significant unobservable inputs, including those that require considerable judgment for which there is little or no market data. 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.

Current and non-current classification

Generally, assets and liabilities (excluding deferred taxes and liabilities subject to compromise) are classified as current assets and liabilities respectively if their maturity is within one year of the balance sheet date. In addition, we classify any derivative financial instruments whose fair value is a net liability as current. Current liabilities will include where amounts from lenders are payable on demand at their discretion due to event of default clauses being met.

Generally, assets and liabilities are classified as non-current assets and liabilities respectively, if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivative financial instruments whose fair value is a net asset as non-current.

Where the liabilities are subject to compromise as part of the Chapter 11 proceedings they are classified separately in the Consolidated Balance Sheet and neither classified as current or non-current.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with maturities of three months or less. Amounts are presented net of allowances for credit losses.

Restricted cash consists of bank deposits which are subject to restrictions due to legislation, regulation or contractual arrangements. Restricted cash amounts that are expected to be used after one year from balance sheet date are classified as non-current assets. Amounts are presented

net of allowances for credit losses, which are assessed based on consideration of whether the balances have short-term maturities and whether the counterparty has an investment grade credit rating, limiting any credit exposure. Refer to Note 12 – "Restricted cash".

Receivables

Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount net of expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 13 - ''Accounts receivable''.

Contract assets and liabilities

Accounts receivables are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. If we recognize revenue ahead of this point, we also recognize a contract asset. Contract assets balances relate primarily to demobilization revenues recognized during the period but are contingent on future demobilization activities.

Contract liabilities include payments received for mobilization, rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. Amounts receivable from related parties are presented net of allowances for expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 19 - ''Related party transactions'' for details of balances and material transactions with related parties.

Use of estimates

Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

In assessing the recoverability of our drilling units carrying amounts, we make assumptions regarding estimated future cash flows, estimates in respect of residual value, day rates, drilling unit operating expenses and overhaul requirements.

Business combinations

We apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred.

Drilling units

Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up rigs, when new, is 30 years. The direct and incremental costs of significant capital projects, such as rig upgrades and reactivation projects, are capitalized and depreciated over the remaining life of the asset.

Drilling units acquired in a business combination are measured at fair value at the date of acquisition. Drilling units were also remeasured to fair value when we applied fresh start accounting at the date of emergence. Cost of property and equipment sold or retired, with the related accumulated depreciation and impairment is removed from the Consolidated Balance Sheet, and resulting gains or losses are included in the Consolidated Statement of Operations.

We re-assess the remaining useful lives of our drilling units when events occur which may impact our assessment of their remaining useful lives. These include changes in the operating condition or functional capability of our rigs, technological advances, changes in market and economic conditions as well as changes in laws or regulations affecting the drilling industry. Refer to Note 15 - ''Drilling units ''.

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: management commits to a plan to sell the asset (disposal group), the asset is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets, an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset is probable, and transfer of the asset is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to be generated from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, we then compare the carrying value of the asset with the discounted future net cash flows, using a relevant weighted-average cost of capital. The impairment loss to be recognized during the period, is the amount by which the carrying value of the asset exceeds the discounted future net cash flows.

Favorable drilling contracts - intangible assets

Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the Consolidated Statements of Operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.

Derivative Financial Instruments and Hedging Activities

Our derivative financial instruments are measured at fair value and are not designated as hedging instruments. Changes in their fair value are recorded as a gain or loss as a separate line item within "financial items" in the Consolidated Statements of Operations. We classify the asset or liability for derivative financial instruments within "other current assets" or "other current liabilities" in our Consolidated Balance Sheets. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements. Refer to Note 21 - ''Fair Value Measurement''.

Trade payables

Trade payables are liabilities to a supplier for a good or service provided to us.

Deferred charges

Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in "interest expense" in the Consolidated Statement of Operations.

Debt

We have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid. Refer to Note 16 - ''Debt''.

Loss contingencies

We recognize a loss contingency in the Consolidated Balance Sheets where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Refer to Note 22 - ''Commitments and contingencies''.

Equity allocation

Earnings and losses attributable to unitholders of Seadrill Partners are allocated to all unitholders on a pro rata basis for the purposes of presentation in the Consolidated Statements of Changes in Members' Capital. Earnings and losses attributable to unitholders for any period are first reduced for any cash distributions for the period to be paid to the holders of the incentive distribution rights.

At the time of the Company's initial public offering, the equity attributable to unitholders was allocated using the hypothetical amounts which would be distributed to the various unitholders on a liquidation of the Company ("hypothetical liquidation method"). This method has also been used to account for issuances of common units by the Company, and the deemed distributions from equity which resulted from acquisitions of drilling units from Seadrill.

Guarantees

Guarantees issued by us, excluding those that are guaranteeing our own performance, are recognized at fair value at the time that the guarantees are issued and reported in "other current liabilities" and "other non-current liabilities" in our Consolidated Balance Sheets. If it becomes probable that we will have to perform under a guarantee, we remeasure the liability if the amount of the loss can be reasonably estimated. The recognition of fair value is not required for certain guarantees such as the parent's guarantee of a subsidiary's debt to a third party. Financial guarantees written are assessed for credit losses and any allowance is presented as a liability for off-balance sheet credit exposures where the balance exceeds the collateral provided over the remaining instrument life. The allowance is assessed at the individual guarantee level, calculated by multiplying the balance exposed on default by the probability of default and loss given default over the term of the guarantee.

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Recent accounting standards

12 Months Ended

Dec. 31, 2020

Accounting Changes and Error Corrections [Abstract]

Recent accounting standards

Recent accounting standards

We adopted the following accounting standard updates ("ASUs") in the year:

a) ASU 2016-13 - Financial Instruments - Measurement of Credit Losses (Also 2018-19, 2019-04 & 2019-11)

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments, including ASU 2018-19, ASU 2019-04 and ASU 2019-11: Codification Improvements to Topic 326 ‘‘Financial Instruments-Credit Losses”. Topic 326 replaces the incurred loss impairment methodology (that recognizes losses when a probable threshold is met) with a requirement to recognize lifetime expected credit losses (measured over the contractual life of the instrument) immediately, based on information about past events, current conditions and forecasts of future economic conditions. Under the current expected credit loss ( the "CECL") measurement financial assets are reflected at the net amount expected to be collected from the financial asset, CECL measurement is applicable to financial assets measured at amortized cost as well as off-balance sheet credit exposures not accounted for as insurance (including financial guarantees).

Using the modified retrospective method, reporting periods beginning after January 1, 2020 are presented under Topic 326 while comparative periods continue to be reported in accordance with previously applicable GAAP and have not been restated. The adoption of Topic 326 did not have a material impact on our condensed consolidated financial statements.

b) ASU 2020-03 Financial Instruments: Codification Improvements

In March 2020, the FASB issued ASU 2020-03 Financial Instruments (Topic 825) - Codification Improvements. The amendments in this ASU propose seven clarifications to improve the understandability of existing guidance, including that fees between debtor and creditor and third-party costs directly related to exchanges or modifications of debt instruments include line-of-credit or revolving debt arrangements. We adopted the codification improvements that were effective on issuance from January 1, 2020 under the specified transition approach connected with each of the codification improvements. This amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2020.

c) Other accounting standard updates

We additionally adopted the following accounting standard updates in the year which did not have any material impact on our Consolidated Financial Statements and related disclosures:

•ASU 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.

•ASU 2018-13 Fair Value Measurement: Changes to the Disclosure Requirements for Fair Value Measurement.

•ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans.

•ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.

•ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities.

•ASU 2019-04 Codification Improvements to Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments.

•ASU 2019-08 Compensation—Stock Compensation (Topic 718) and Revenue from Contracts with Customers (Topic 606): Codification Improvements—Share-Based Consideration Payable to a Customer.

2) Recently issued accounting standards

Recently issued ASUs by the FASB that we have not yet adopted but which could affect our Consolidated Financial Statements and related disclosures in future periods:

a) ASU 2019-12 Income Taxes (Topic 740): Simplifying the accounting for income taxes

In December 2019, the FASB issued ASU 2019-12. The amendments in this update simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance will be effective from January 1, 2021 on a mainly prospective basis, with early adoption permitted. This amendment will have no material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2021.

b) ASU 2020-04 Reference Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04. The amendments provide temporary optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The applicable expedients for us are in relation to modifications of contracts within the scope of Topics 310, Receivables, 470, Debt, and 842, Leases. This optional guidance may be applied prospectively from any date beginning March 12, 2020 and cannot be applied to contract modifications that occur after December 31, 2022. We are in the process of evaluating the impact of this standard update on our consolidated financial statements and related disclosures.

c) Other accounting standard updates issued by the FASB

As of April 30, 2021, the FASB have issued several further updates not included above. We do not currently expect any of these updates to affect our Consolidated Financial Statements and related disclosures either on transition or in future periods.

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Chapter 11 Proceedings

12 Months Ended

Dec. 31, 2020

Reorganizations [Abstract]

Previous Chapter 11 Proceedings

Chapter 11 Proceedings

Bankruptcy proceedings under Chapter 11

On December 1, 2020, Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”), triggering a stay on enforcement of remedies with respect to our debt obligations. As part of the Chapter 11 proceedings, the Debtors were granted “first-day” relief which enables us to continue operations without interruption. On February 12, 2021, the Debtors and certain of their prepetition lenders executed a plan support agreement, which contemplates a series of restructuring transactions that will equitize approximately $2.7 billion in secured term loan obligations and select go-forward, value maximizing services providers.

ASC 852-10, Reorganizations, applies to entities that have filed a petition for relief under Chapter 11 of the Bankruptcy Code. In accordance with ASC 852-10, transactions and events directly associated with the reorganization are required to be distinguished from the ongoing operations of the business. In addition, the guidance requires changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.

We may be required to adopt fresh start accounting upon emergence from Chapter 11. Adopting fresh start accounting would result in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the emerging company is based on several assumptions and inputs contemplated in the future projections of the plan of reorganization and are subject to significant uncertainties. We currently cannot estimate the potential financial effect of fresh start accounting on our consolidated financial statements upon the emergence from Chapter 11, although we would expect to recognize material adjustments upon implementation of fresh-start accounting guidance upon emergence pursuant to a plan of reorganization.

Liabilities subject to compromise

Liabilities subject to compromise distinguish pre-petition liabilities which may be affected by the Chapter 11 proceedings from those that are not and those post-petition. These amounts represent our allowed claims and our best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. This is disclosed on a separate line in between current and non-current liabilities on the consolidated balance sheet.

Liabilities subject to compromise represent our estimate of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. Such claims remain subject to future adjustments which may result from: (i) negotiations; (ii) actions of the Bankruptcy Court; (iii) disputed claims; (iv) rejection of executory contracts and unexpired leases; (v) the determination as to the value of any collateral securing claims; (vi) proofs of claim; or (vii) other events. Such future adjustments will potentially be material.

Liabilities subject to compromise, as presented on the Consolidated Balance Sheet as at December 31, 2020, include the following:

(In $ millions)	2020
Senior undersecured or impaired external debt	2,727.1
Derivatives previously recorded at fair value	20.8
Accounts payable and other liabilities	24.4
Accrued interest payable	32.5
Amount due to related party	74.3
Liabilities subject to compromise	2,879.1

While operating as a Debtor-in-Possession under Chapter 11 of the Bankruptcy Code, the Debtors may sell, otherwise dispose of, liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business, in amounts other than those reflected in the Consolidated Financial Statements. Moreover, a plan of reorganization could materially change the amounts and classifications of assets and liabilities in the historical Consolidated Financial Statements.

Interest expense

The Debtors have discontinued recording interest on the under-secured debt facility, classified under liabilities subject to compromise, from the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Consolidated Statement of Operations was $21.3 million.

Potential claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing.

All holders of pre-petition claims except governmental units were required to file proofs of claim by February 15, 2021 (the "Bar Date"). Governmental units holding claims against the Debtors are required to file proof of claim by May 30, 2021. At the Bar Date, 285 claims totaling approximately $3.2 billion had been filed with the Bankruptcy Court against the Debtors. Subsequent to this date, approximately 120 further claims have been processed but this has not materially impacted the overall amount claimed against the Debtors.

It is possible that claimants will file amended claims in the future, including claims amended to assign values to claims originally filed with no designated value. Through the claims resolution process, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We will file objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Claims we believe are allowable are reflected in "Liabilities Subject to Compromise" in the Consolidated Balance Sheets.

Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the number of claims filed, the claims resolution process will take additional time to complete, and it may continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Executory Contracts

Under the Bankruptcy Code, the Debtors have the right to assume, amend and assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a prepetition general unsecured claim for damages.

Reorganization items, net

Incremental costs incurred directly as a result of the Bankruptcy Filing and gains on the settlement of liabilities under the Plan are classified as "Reorganization items, net" in the Consolidated Statements of Operations. The following table summarizes reorganization items:

(In $ millions)	2020
Advisory and professional fees	7.1
Unamortized debt issuance costs	42.9
Interest income on surplus cash invested	(0.2)
Reorganization items, net	49.8

Condensed Combined Debtors Financial Statements

As the non-debtor entities do not materially contribute to the Group financial position, we have not presented condensed combined financial statements specific to the Debtor group as a separate disclosure. For the Group financial position, please refer to the consolidated financial statements included herein.

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Segment information

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Segment information

Segment information

Operating segment

We regard our fleet as one single operating segment. The Chief Operating Decision Maker, which is the Board of Directors, review performance at this level as an aggregated sum of assets, liabilities and operating income.

A breakdown of our revenues by customer for the years ended December 31, 2020, 2019 and 2018 is as follows: 

	2020		2019		2018
BP	75.8	%	67.6	%	68.0	%
Reliance	8.6	%	—	%	—	%
ExxonMobil	8.3	%	11.0	%	0.3	%
Petronas	5.5	%	9.9	%	—	%
Chevron	—	%	7.2	%	8.5	%
Tullow	—	%	—	%	19.8	%
Other	1.8	%	4.3	%	3.4	%
Total	100	%	100	%	100	%

Geographic Data

Revenues are attributed to geographical areas based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the revenues for the years ended December 31, 2020, 2019 and 2018 and fixed assets as of December 31, 2020 and 2019 by geographic area:

Revenues

(In $ millions)	2020	2019	2018
United States	409.4	539.1	618.1
India	46.0	—	—
Canada	45.2	60.9	85.3
Malaysia	36.9	40.1	—
Thailand	0.2	53.8	88.7
Gabon	0.2	21.2	—
Myanmar	—	17.8	—
Ghana	—	—	205.5
Other	0.2	17.1	40.6
Total	538.1	750.0	1,038.2

Fixed Assets—Drilling Units (1)  

(In $ millions)	2020	2019
United States	153.8	2,561.7
Malaysia	88.2	607.1
India	53.9	—
Canada	53.8	451.7
Aruba	51.5	—
Singapore	27.1	108.8
Namibia	—	502.5
Norway	—	499.2
Thailand	—	109.8
Total	428.3	4,840.8

(1)The fixed assets referred to in the table above include the 11 drilling units at December 31, 2020 and December 31, 2019. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

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Revenue from contracts with customers

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue from contracts with customers

Revenue from contracts with customers

The following table provides information about receivables and contract liabilities from our contracts with customers:

(In $ millions)	2020	2019
Accounts receivable, net	56.6	146.7
Current contract liabilities (deferred revenues) (1)	0.9	3.0

(1)  Current contract liabilities balances are included in "other current liabilities" in our Consolidated Balance Sheets as at December 31, 2020.

Significant changes in the contract liabilities balances during the year ended December 31, 2020 are as follows:

(In $ millions)	2020	2019
Contract liabilities at start of period	3.0	6.4
Decrease due to amortization of revenue that was included in the beginning contract liability balance	(3.0)	(9.3)
Increase due to cash received, excluding amounts recognized as revenue	0.9	5.9
Contract liabilities at end of period	0.9	3.0

The deferred revenues balance of $0.9 million reported in "other current liabilities" at December 31, 2020 is expected to be realized within the next twelve months.

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Taxation

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Taxation

Taxation

Income taxes consist of the following:

(In $ millions)	2020	2019	2018
Current tax expense / (benefit):
U.K.	—	—	(0.3)
Foreign	28.3	(39.3)	86.3
Total current tax expense / (benefit)	28.3	(39.3)	86.0
Deferred tax expense / (benefit):
Foreign	1.7	3.2	0.7
Total income tax expense / (benefit)	30.0	(36.1)	86.7

Seadrill Partners LLC is tax resident in the U.K. The Company's controlled affiliates operate and earn income in several countries and are subject to the laws of taxation within those countries. Currently some of the Company's controlled affiliates formed in the Marshall Islands along with all those incorporated in the U.K. (none of whom presently own or operate rigs) are resident in the U.K. and are subject to U.K. tax. Subject to changes in the jurisdictions in which the Company's drilling units operate and/or are owned, differences in levels of income and changes in tax laws, the Company's effective income tax rate may vary substantially from one reporting period to another.

The Company's effective income tax rate for each of the years ended on December 31, 2020, 2019 and 2018 differs from the U.K. statutory income tax rate as follows:

	2020		2019		2018
U.K. statutory income tax rate	19.0	%	19.0	%	19.0	%
Non-U.K. taxes	(19.7)	%	(2.8)	%	35.0	%
Effective income tax rate	(0.7)	%	16.2	%	54.0	%

Due to the CARES Act in the U.S., the Company recognized a tax benefit of $6 million by carrying back net operating losses to previous years.

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

Our deferred tax assets consist of the following:

(In $ millions)	2020	2019
Provisions	54.9	0.6
Net operating losses carry forward	221.5	77.5
Interest carry forward	—	29.6
Property, plant and equipment	174.5	—
Other	3.6	5.3
Gross deferred tax assets	454.5	113.0
Valuation allowance	(451.6)	(107.1)
Deferred tax asset, net of valuation allowance	2.9	5.9

Our deferred tax liabilities consist of the following:

(In $ millions)	2020	2019
Property, plant and equipment	—	0.1
Unremitted earnings of subsidiaries	0.6	1.7
Gross deferred tax liabilities	0.6	1.8
Net deferred tax asset	2.3	4.1

As of December 31, 2020, deferred tax assets related to net operating loss ("NOL") carryforwards were $221.5 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $51.9 million which will not expire and $169.6 million that will expire between 2022 and 2037 if not utilized. Primarily due to the impairment of rigs, we generated deferred tax assets related to NOL of $218.9 million and Property, plant and equipment (“PP&E”) of $174.5 million in 2020. We establish a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change. Our valuation allowance primarily consists of $220.7 million on NOL carryforward, $174.7 million on PP&E and $55.4 million on interest carryforward.

Uncertain tax positions

As of December 31, 2020, the Company had a total amount of unrecognized tax benefit of $39.2 million (December 31, 2019: $40.2 million), excluding of interest and penalties included in "other non-current liabilities" on the Consolidated Balance Sheets. The changes to the Company's balance related to unrecognized tax benefits were as follows:

(In $ millions)	2020	2019
Balance beginning of year	40.2	101.6
Increases as a result of positions taken in prior years	—	1.1
Decreases as a result of positions taken in prior years	(1.0)	(60.7)
Settlements	—	(1.8)
Unrecognized tax benefits	39.2	40.2

Accrued interest and penalties totaling $5.2 million as of December 31, 2020 (December 31, 2019: $4 million) were included in "other non-current liabilities" on the Consolidated Balance Sheets. The Company recognized interest and penalty expense of $1.2 million as "Income tax (expense)/benefit" in the Consolidated Statements of Operations during the year ended December 31, 2020 (December 31, 2019: $12.4 million benefit and December 31, 2018: $8.4 million expense).

As of December 31, 2020, $44.4 million of our unrecognized tax benefit, including penalties and interest, would have a favorable impact to the Company's effective tax rate if recognized.

Tax examinations

The Company is subject to taxation in various jurisdictions. The Ghana tax authorities have issued a series of assessments with respect to our returns for certain years up to 2018 in respect of indirect and direct taxes. The assessments are for an aggregate amount of $18 million as of the date of this report. These assessments are being robustly contested including filing relevant appeals. An adverse outcome on these proposed assessments could result in a material adverse impact on our Consolidated Balance Sheets, Statement of Operations or Cash flows.

The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:

Jurisdiction	Earliest Open Year
United States	2016
Nigeria	2012
Ghana	2013

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Other revenues

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Other revenues

Other revenues

Other revenues comprise the following items: 

(In $ millions)	2020	2019	2018
Early termination revenue	—	41.0	204.9
Related party other revenues	1.1	1.8	4.6
Total	1.1	42.8	209.5

Early termination revenue for the year ended December 31, 2019 was $41 million, relating to termination fees recognized for the West Capricorn and West Vencedor.

Early termination revenue for the year ended December 31, 2018 was $204.9 million, relating to the West Leo litigation judgment (refer to Note 22 - ''Commitments and contingencies'' for further information).

Related party other revenues primarily relate to revenue from the sale of inventories and spare parts to Seadrill. Please refer to Note 19 – "Related party transactions" for further detail on related party other revenues.

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Other operating items

12 Months Ended

Dec. 31, 2020

Other Operating Gains (Losses) [Abstract]

Other operating items

Other operating items

Other operating items comprise the following: 

(In $ millions)	2020	2019	2018
Loss on impairment of goodwill	—	—	(3.2)
Revaluation of contingent consideration	—	0.7	—
Impairment of long-lived assets	(4,210.4)	—	—
Total	(4,210.4)	0.7	(3.2)

During the year ended December 31, 2020 we recognized an impairment against our long-lived assets of $4,210.4 million. For further information refer to Note 10 - "Impairment of long-lived assets".

There was a gain on revaluation of contingent consideration of $0.7 million for the year ended December 31, 2019. This gain resulted from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015.

During the year ended December 31, 2018, we recognized a loss on impairment of goodwill following early adoption of ASU 2017-04, Intangibles. For further information refer to Note 3 - ''Recent accounting standards''.

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Impairment of long-lived assets

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Impairment of long-lived assets

Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. In 1Q20, as a result of the deteriorating market due to COVID-19 and oil price declines, there was an impairment triggering event and we recognized an impairment of $922.9 million in respect of certain idle drilling units. In 4Q20, our view was that the challenging market conditions are likely to persist for a sustained period and that certain of our cold stacked units are unlikely to return to the working fleet, so have concluded there is a further impairment triggering event for our drilling unit fleet and we recognized an impairment of $3,287.5 million.

On assessment of asset recoverability through an estimated undiscounted future net cash flow we calculated the value to be lower than the carrying value for all of our rigs, of which we recognized full impairments of the West Sirius and West Leo and partial impairments for all other rigs. This resulted in impairment expenses of $4,210.4 million during 2020 which were classified within “impairment of long-lived assets” on our Consolidated Statement of Operations for the year ended December 31, 2020.

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Interest expense

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Interest expense

Interest expense

Interest expense consists of the following:

(In $ millions)	2020	2019	2018
Interest on debt facilities (1)	189.2	246.3	245.3
Loan fee amortization (2)	44.2	12.3	12.7
Other (3)	1.9	3.9	5.7
Total interest expense	235.3	262.5	263.7

(1) We are charged interest on our debt facilities at rates explained in Note 16 - "Debt". As a result of filing for Chapter 11, no interest has been recognized from December 1, 2020. For further details refer to Note 4 - "Chapter 11 Proceedings".

(2) We incur loan fees on our debt facilities that are amortized over the term of the loan. The increase in 2020 is due to commitment and exit fees incurred on the new super senior loans. For further details refer to Note 16 - "Debt".

(3) Other interest expense primarily relates to the unwind of the discount on contingent consideration payable to Seadrill. For further details refer to Note 19 - "Related party transactions".

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Restricted cash	12 Months Ended
	Dec. 31, 2020
Cash and Cash Equivalents [Abstract]
Restricted cash	Restricted cashRestricted cash consists of $16.4 million as at December 31, 2020 (December 31, 2019: nil) for cash held as collateral for a guarantee with Danske Bank to provide security for the payment, discharge and performance of secured obligations.

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Accounts receivable	12 Months Ended
	Dec. 31, 2020
Accounts Receivable, after Allowance for Credit Loss, Current [Abstract]
Accounts receivable	Accounts receivableAccounts receivable are held at their nominal amount less an allowance for expected credit losses. The adoption of ASC 326 on January 1, 2020 did not have a material impact on our third-party accounts receivable balances either on transition or at the year end. In calculating the expected credit losses we assumed that the accounts receivable are performing, mature within three months and have a Baa3 credit rating. Refer to Note 2 - "Accounting policies" for further information.

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Other assets

12 Months Ended

Dec. 31, 2020

Other Assets [Abstract]

Other assets

Other assets

Other assets include the following:

(In $ millions)	2020	2019
Intangible asset - Favorable contracts	—	40.4
Mobilization revenue receivables	—	22.3
Prepaid expenses	26.7	14.1
Income taxes receivable	13.0	19.3
VAT receivable	5.7	10.6
Deferred mobilization costs	3.0	7.5
Reimbursable amounts due from customers	1.5	3.5
Other	3.1	1.8
Total other assets	53.0	119.5

Other assets are presented in our Consolidated Balance Sheet as follows:

(In $ millions)	2020	2019
Other current assets	45.0	119.5
Other non-current assets (1)	8.0	—
Total other assets	53.0	119.5

(1) Relates to prepaid Directors and Officers insurance cover relating to tail back claims in the Chapter 11 process.

Mobilization revenue receivables

Under our contracts for the West Auriga and West Vela, we are paid for mobilization activities over the contract term. We recorded a financial asset equal to the fair value of this future stream of payments when we acquired these drilling units from Seadrill. We collected these amounts over the term of the drilling contracts which completed in October 2020 and November 2020, respectively. We record the unwind of the time value of money discount as interest income.

Favorable contracts

Favorable drilling contracts are recorded as intangible assets at fair value on the date of acquisition less accumulated amortization. The amounts recognized represent the net present value of the existing contracts at the time of acquisition compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. The estimated favorable contract values have been recognized and amortized on a straight line basis over the terms of the contracts, ranging from two to five years.

Favorable contracts to be amortized relate to the favorable contracts acquired with the West Auriga and the West Vela from Seadrill as at December 31, 2020. These were fully amortized in October 2020 and November 2020 respectively. The gross carrying amounts and accumulated amortization included in "other current asset"' and "other non-current assets" in the Consolidated Balance Sheets were as follows:

	2020			2019
(In $ millions)	Gross carrying amount	Accumulated amortization	Net carrying amount	Gross carrying amount	Accumulated amortization	Net carrying amount
Intangible assets- Favorable contracts
Balance at beginning of period	357.3	(316.9)	40.4	357.3	(271.8)	85.5
Amortization of favorable contracts	—	(40.4)	(40.4)	—	(45.1)	(45.1)
Balance at end of period	357.3	(357.3)	—	357.3	(316.9)	40.4

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Drilling units

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Drilling units

Drilling units 

The below table shows the gross value and net book value of our drilling units at December 31, 2020 and December 31, 2019.

(In $ millions)	Cost	Accumulated depreciation	Net Book Value
Opening balance as at January 1, 2019	6,714.0	(1,708.4)	5,005.6
Additions	111.1	—	111.1
Depreciation	—	(275.9)	(275.9)
Closing balance as at December 31, 2019	6,825.1	(1,984.3)	4,840.8
Additions	28.7	—	28.7
Impairment	(4,210.4)	—	(4,210.4)
Depreciation	—	(230.8)	(230.8)
Closing balance as at December 31, 2020	2,643.4	(2,215.1)	428.3

Depreciation related to our drilling units was $230.8 million, $275.9 million and $280.3 million for the years ended December 31, 2020, 2019 and 2018 respectively.

Each of our drilling units has been pledged as collateral under our debt agreements. Please refer to Note 16 – "Debt" for further details.

We recognized an impairment expense of $4,210.4 million which was classified within "impairment of long-lived assets" on our Consolidated Statement of Operations for the year ended December 31, 2020. Please refer to Note 10 - "Impairment of long-lived assets" for further details.

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Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt

Debt

As at December 31, 2020 and December 31, 2019, we had the following debt amounts outstanding:

(In $ millions)	2020	2019
External debt agreements
Term Loan B	2,727.1	2,607.6
West Vela Facility	—	151.0
West Polaris Facility	—	114.9
Tender Rig Facility	—	18.6
Total external debt	2,727.1	2,892.1
Less: Debt balance held as subject to compromise	(2,727.1)	—
Debt balance not subject to compromise	—	2,892.1

Chapter 11 Proceedings

We filed for Chapter 11 bankruptcy protection on December 1, 2020 which triggered an event of default under the Term Loan B. As a result, the outstanding balance on this loan was classified within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings".

On filing for Chapter 11, $42.9 million of unamortized debt issuance costs on the Term Loan B were expensed and recognized within "Reorganization items, net" in the Consolidated Statement of Operations and no further interest was recorded on the Term Loan B from that point.

Term Loan B

Our Term Loan B facilities ("TLB") initially consisted of a term loan and a linked $100 million revolving credit facility. We initially borrowed $1.8 billion under the term loan on February 21, 2014 and then a further $1.1 billion on June 26, 2014. This loan is subject to a 1% per year ($29 million) amortization payment with the balance of the loan then being repayable in February 2021. The revolving credit facility matured in February 2019.

We agreed with the TLB lenders to amend the TLB agreement in July and October 2020 respectively, whereby the majority of the TLB interest that was due on June 30, 2020 and September 30, 2020 was converted into super senior loans ($8 million of TLB interest was cash settled to lenders that withheld consent). As a result, $63.7 million and $63.3 million super senior loans, maturing in February 2021 were created. These loans each included a non-cash $20 million commitment fee and an exit fee of 10% in addition to the interest settled through issuance of the loans.

We had a total of $2,727.1 million outstanding on the TLB at December 31, 2020

During the year ended December 31, 2020, we paid interest of LIBOR + 6% on the original term loan and LIBOR + 10% on the super senior loans. LIBOR is subject to a 1% floor. As of the date of filing for Chapter 11 we are subject to an additional 2% default interest, however we have discontinued recording interest. For further information refer to Note 4 - "Chapter 11 Proceedings".

Following an amendment to the TLB agreement, and the repayment of the other loan facilities (see below) all rigs are pledged as collateral vessels under the TLB. The net book value of these drilling units at December 31, 2020 was $428.3 million. We have also pledged substantially all the assets of our subsidiaries, which own or charter the collateral vessels as well as our investments in those companies.

West Vela facility

The West Vela facility consisted of a term loan with four tranches. We initially incurred the liability to repay $443 million under this term loan when we acquired the West Vela from Seadrill in November 2014. The loan was subject to amortization payments of $40.3 million per year. We made a prepayment of $46.7 million in August 2017 and further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The $120.8 million balloon payment was repaid in July 2020.

We paid interest on the term loan at LIBOR plus a margin of between 3.35% and 4%, inclusive of guarantee fees, depending on the tranche.

West Polaris facility

The West Polaris facility consisted of a term loan and a linked revolving credit facility. We initially incurred the liability to repay $226 million under this term loan and $100 million under the revolving credit facility when we acquired the West Polaris from Seadrill in June 2015. The loan was subject to amortization payments of $36 million per year. We made a prepayment of $37.4 million in August 2017 and further prepayments of $9.4 million in February 2018 and August 2018. The $93.8 million balloon payment was repaid in July 2020.

We paid interest on the term loan and revolving credit facility at LIBOR plus a margin of 3.25%. We also paid a commitment fee of 1.3% on any unused portion of the revolving credit facility.

Tender rig facility

The Tender Rig facility consisted of two term loans. We initially borrowed $100.5 million and $93.1 million under intercompany loans from Seadrill when we acquired the T-15 and T-16 in May 2013 and October 2013 respectively. These intercompany loans were back to back with an external debt facility Seadrill had used to finance the construction of the T-15 and T-16. In August 2017, we amended the terms of these loans so that we held the facility directly with the external lender.

We were required to make amortization payments of $19.8 million per year against this facility. We made a prepayment of $15.8 million in August 2017 when we amended the facility and paid further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The Tender Rig facility included a "satisfactory drilling contract" covenant. As a consequence of the T-16 and T-15 not having a satisfactory drilling contract for a period of time, the facility became due on a pro rata basis. In November 2019 there was an early repayment of the entirety of the T-16 balance of $20.0 million. The remaining $2.7 million and $15.9 million balloon payments related to the T-15 were repaid in March and April 2020 respectively. We paid interest on these loans at LIBOR plus a margin of 4.25%.

Presentation in Consolidated Balance Sheets

We present external debt net of debt issuance costs. The below tables show how the above balances are presented in the Consolidated Balance Sheets:

	Outstanding debt as at December 31, 2020
(In $ millions)	Principal outstanding	Debt Issuance Costs (1)	Total Debt
Debt held as subject to compromise	2,727.1	—	2,727.1
Total interest-bearing debt	2,727.1	—	2,727.1

	Outstanding debt as at December 31, 2019
(In $ millions)	Principal outstanding	Debt Issuance Costs	Total Debt
Debt due within twelve months	313.3	(11.9)	301.4
Long-term external debt	2,578.8	(2.0)	2,576.8
Total interest-bearing debt	2,892.1	(13.9)	2,878.2

(1) On filing for Chapter 11 on December 1, 2020 all unamortized debt issuance costs on under secured debt have been written off to "reorganization items, net" in our Consolidated Statement of Operations. For further details refer to Note 4 - "Chapter 11 Proceedings".

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Other liabilities

12 Months Ended

Dec. 31, 2020

Payables and Accruals [Abstract]

Other liabilities

Other liabilities

Other liabilities are comprised of the following: 

(In $ millions)	2020	2019
Uncertain tax position	44.4	44.2
Accrued expenses	13.1	34.0
Taxes payable	31.8	35.1
Interest rate swap agreements (1)	—	17.7
Employee and business withheld taxes, social security and vacation payment	8.3	9.0
VAT payable	2.2	4.7
Deferred mobilization/demobilization revenues (see Note 6 - "Revenue from contracts with customers")	0.9	3.0
Total other liabilities (2)	100.7	147.7

Other liabilities are classified in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Other current liabilities	56.3	103.5
Other non-current liabilities	44.4	44.2
Total other liabilities (1)	100.7	147.7

(1) In preparation for Chapter 11 filing, a decision was made to default on the interest rate swap payments that were due on November 23, 2020. As a result, the outstanding derivative balance on this date was held at the counterparty claimed value within "liabilities subject to compromise" on our Consolidated Balance Sheets as at December 31, 2020. Refer to Note 20 - "Risk management and financial instruments" for more information.

(2) Balances held as at December 31, 2020 exclude liabilities that are subject to compromise, which have been reclassified to a separate line within the Consolidated Balance Sheet. This represents our estimate of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. For further information refer to Note 1 - "General information".

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Non-controlling interest

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

Non-controlling interest

Non-controlling interest

Changes in non-controlling interests for the periods presented in this report were as follows:

(In $ millions)	Non-controlling interest
December 31, 2018	1,384.5
Share of net loss allocated to the non-controlling interest	(94.3)
Cash distributions	(1.5)
December 31, 2019	1,288.7
Share of net loss allocated to the non-controlling interest	(2,038.0)
December 31, 2020	(749.3)

Our non-controlling interest consists of Seadrill Limited's 42% interest in Seadrill Operating LP and 49% interest in Seadrill Capricorn Holdings LLC. Of which, we hold the following:

(1) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Capricorn Holdings LLC owns 100% of the entities that own and operate the West Capricorn, West Sirius, West Auriga and West Vela.

(2) a 58% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through our 100% ownership of its general partner, Seadrill Operating GP LLC. Seadrill Operating LP owns: (a) 100% interest in the entities that own the West Aquarius, West Leo, West Polaris and the West Vencedor, (b) approximately 56% interest in Seadrill Deepwater Drillship that owns and operates the West Capella and (c) a 51% limited liability interest in Seadrill Mobile Units (Nigeria).

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Related party transactions

12 Months Ended

Dec. 31, 2020

Related Party Transactions [Abstract]

Related party transactions

Related party transactions

The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2020, 2019 and 2018.

(In $ millions)	2020	2019	2018
Related party inventory sales (a)	1.1	1.8	3.2
Rig operating costs (b)	—	—	1.4
Total related party operating revenues	1.1	1.8	4.6
Management and technical support fees (c) (d)	60.1	70.5	70.6
Rig operating costs (e)	—	—	0.8
Related party inventory purchases (a)	1.4	1.1	0.7
Total related party operating expenses	61.5	71.6	72.1
Interest expense recognized on deferred contingent consideration (h)	(2.0)	(3.3)	(3.1)
Related party interest expense (f)	—	—	(1.4)
Total related party financial items	(2.0)	(3.3)	(4.5)

The below table provides a summary of amounts due to or from Seadrill at December 31, 2020 and December 31, 2019.

(In $ millions)	2020	2019
Trading balances due from Seadrill and subsidiaries (g)	7.6	6.9
Total related party receivables	7.6	6.9

(In $ millions)	2020	2019
Trading balances due to Seadrill and subsidiaries (g)	78.9	79.5
Deferred and contingent consideration to related party - short term portion (h)	2.8	31.5
Total related party payables	81.7	111.0
Less: Related party payables held as subject to compromise	(74.3)	—
Related party payables not subject to compromise	7.4	111.0

Chapter 11 proceedings

On filing for Chapter 11, our pre-petition related party payables are held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings" of our Consolidated Financial Statements included herein.

(a) Related party inventory sales and purchases

Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.

(b) Rig operating costs charged to Seadrill

Seadrill Partners has charged to Seadrill Limited, through its Nigerian service company, certain services including the provision of onshore and offshore personnel, which was provided for the West Jupiter drilling rig operating in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended in 2018.

(c) Management and administrative services agreement

Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged an allocation for these services on a cost plus mark-up basis. During the year ended December 31, 2020, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreements for certain rigs have been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(d) Operations and technical supervision agreements

In addition, certain subsidiaries of Seadrill Partners have advisory, technical and/or administrative services agreements with subsidiaries of Seadrill. An allocation of these services are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services. This agreements has been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(e) Rig operating costs charged by Seadrill

Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged an allocation for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%.

(f) Interest expense charged by Seadrill

Interest expense charged by Seadrill for the West Vencedor loan arrangement that was due to Seadrill. The loan was repaid during 2018.

(g) Trading balances

Receivables and payables with Seadrill Limited and its subsidiaries are comprised of management fees, advisory and administrative services, and certain other amounts due. Receivables and payables are generally settled quarterly in arrears for those balances that are not held as liabilities subject to compromise. Trading balances to Seadrill Partners and its subsidiaries are unsecured.

(h) Deferred consideration to related party

We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela remaining which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020.

On the West Vela we are required to pay to Seadrill $42k per day for mobilization and a further $40k per day adjusted for utilization over the remaining contract term with BP, which completed in November 2020.

On the West Polaris we agreed to pay Seadrill 100% of dayrate earned above $450k per day for the remainder of the contract with ExxonMobil and 50% of the dayrate earned above $450k per day on any subsequent contract until March 2025. In the year ended December 31, 2019, following reductions in future dayrate estimates and re-contracting assumptions, we impaired the remaining value of the liability to a nil carrying value, resulting in a $0.7 million gain in the Consolidated Statement of Operations.

The below table sets out the fair value of the liabilities at December 31, 2020 and December 31, 2019.

(In $ millions)	2020	2019
West Vela
Mobilization due to Seadrill	2.8	17.2
Seadrill share of dayrate from BP contract	—	14.3
Total	2.8	31.5

These liabilities are presented in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Current deferred and contingent consideration to related party	—	31.5
Liabilities subject to compromise	2.8	—
Total	2.8	31.5

Other agreements and transactions with Seadrill

Equity Distribution

During the year ended December 31, 2018, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions.

A total cash distribution of $6.2 million has been distributed to Seadrill in the year ended December 31, 2018.

These transactions were presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2018.

Spare parts agreement with Seadrill

During the year ended December 31, 2015, we entered an agreement with Seadrill to store spare parts of the West Sirius rig while it was cold stacked. Seadrill may use the spare parts during the stacking period, but must replace them at its own cost when the West Sirius returns to operations.

Guarantees

Seadrill provided performance guarantees to certain of our customers on our behalf for contracts that matured in 2020. These totaled nil as at December 31, 2020 (December 31, 2019: $15 million).

Omnibus agreement

In 2012 we entered into an Omnibus Agreement with Seadrill Limited. The agreement outlines the following provisions: (i) a non-competition agreement with Seadrill for any drilling rig operating under a contract for five or more years; (ii) rights of first offer on any proposed sale, transfer or other disposition of drilling rigs; (iii) rights of first offer on any proposed transfer, assignment, sale or other disposition of any equity interest in Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC (the "OPCO"); and (iv) indemnification – Old Seadrill Limited agreed to indemnify Seadrill Partners against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to Seadrill Partners, and also certain tax liabilities.

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Risk management and financial instruments

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk management and financial instruments

Risk management and financial instruments

We are exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. We may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.

Due to the filing of the Bankruptcy Petitions, interest is no longer incurred on our debt facilities. Prior to filing for Chapter 11, we entered into a derivative agreement to mitigate the risk of interest rate fluctuations. We defaulted on payments due on the interest rate swaps on November 23, 2020 in preparation for the Chapter 11 filing.

As a result, our counterparties terminated all outstanding transactions governed by the International Swaps and Derivatives Association, Inc. ("ISDA"). The derivative transactions are recognized at the recoverable amount under the ISDA's as agreed with our lenders. As at December 31, 2020 we had $20.8 million in estimated derivative instrument settlements payable, reflected as "liabilities subject to compromise" in our Consolidated Balance Sheets.

Interest rate risk management

Our exposure to interest rate risk relates mainly to our floating interest rate debt and balances of surplus funds placed with financial institutions. The exposure related to our floating interest debt has reduced since filing for Chapter 11 as interest is no longer incurred on our debt facilities. Our objective is to obtain the most favorable interest rate borrowings available without increasing its exposure to fluctuating interest rates. Surplus funds are used to repay revolving credit tranches or placed in accounts and deposits with reputable financial institutions in order to maximize returns, while providing us with flexibility to meet all requirements for working capital and capital investments. The extent to which we utilize interest rate swaps to manage our interest rate risk is determined by our net debt exposure and our views on future interest rates.

Interest rate swap agreements

As at November 23, 2020, we had interest rate swaps for a combined outstanding principal amount of $2,714.1 million, (December 31, 2019: $2,735.8 million) swapping floating rate for an average fixed rate of 2.49% per annum. The fair value of the interest rate swaps outstanding as of December 31, 2020 was a liability of $20.8 million (December 31, 2019: liability of $17.7 million). The collateral vessels under our TLB have been pledged as collateral against our interest rate swap liabilities. The interest rate swaps are secured on a pari passu basis with the TLB lenders. The swap providers rank lower on the payment waterfall with regards to the super senior loan.

We record interest rate swaps on a net basis where netting is allowed under ISDA Master Agreements. We classify the net asset or liability within other current assets or current liabilities. We have not designated any interest swaps as hedges and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statements of Operations under "loss/gain on derivative financial instruments".

On December 1, 2020, the interest rate swaps were terminated under the ISDA and an adjustment for credit risk on the interest rate swap position was reversed to "other financial expenses" in the Consolidated Statement of Operations, totaling $7.1 million. The residual liability represents the counterparty claimed value of $20.8 million, which was reclassified to "liabilities subject to compromise" in our Consolidated Balance Sheets as at December 31, 2020.

The total realized and unrealized loss recognized under "loss/gain on derivative financial instruments" in the Consolidated Statements of Operations relating to interest rate swap agreements for 2020 was a loss of $16.1 million (2019: loss of $27.7 million, 2018: gain of $24.9 million).

Our interest rate swap agreements as at November 23, 2020, were as follows:

Maturity date	Outstanding principal as at November 23, 2020		Receive rate	Pay rate
	(In $ millions)
February 21, 2021	2,714.1		3 month LIBOR	2.45% to 2.52%	(1) (2)
Total outstanding principal	$	2,714.1

(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.

(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.

Following the defaults on our debt and the termination of our derivatives in 2020 we no longer have any net exposure to short term fluctuations in interest rates. As at December 31, 2019, $156.3 million of our debt was exposed to interest rate fluctuations.

The credit exposure of interest rate swap agreements is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements, adjusted for counterparty non-performance credit risk assumptions. It is our policy to enter into ISDA Master Agreements, with the counterparties to derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes us.

Foreign currency risk

We use the U.S. Dollar as the functional currency of all our subsidiaries because the majority of our revenues and expenses are denominated in U.S. Dollars. Therefore, we also use U.S. Dollars as our reporting currency.

Our foreign currency risk arises from:

•the measurement of monetary assets and liabilities denominated in foreign currencies converted to U.S. Dollars, with the resulting gain or loss recorded as "currency exchange loss/gain"; and

•the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies.

We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.

Credit risk

We have financial assets which expose us to credit risk arising from possible default by a counterparty. Our counterparties primarily include our customers, which are international oil companies, national oil companies or large independent companies or financial institutions. We consider these counterparties to be creditworthy and do not expect any significant loss due to credit risk. We don't demand collateral from our counterparties in the normal course of business. Credit risk is also considered as part of our expected credit loss provision. Refer to Note 2 - "Accounting policies" for further information.

Concentration of Credit Risk

There is a concentration of credit risk with respect to revenue as one of our customers represent more than 10% of total revenues. Refer to Note 5 - "Segment information" for an analysis of our revenue by customer. The market for our services is the offshore oil and gas industry, and our customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral from them. Reserves for potential credit losses are maintained when necessary.

There is a concentration of credit risk with respect to cash and cash equivalents as most of the amounts are deposited with Nordea Bank Finland Plc and Danske Bank A/S. We consider these risks to be remote given the investment grade credit rating of these banks.

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Fair Value Measurement

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurement

Fair Value Measurement

Fair value of financial assets and liabilities measured at amortized cost

The carrying value and estimated fair value of our financial instruments that are measured at amortized cost as of December 31, 2020 and December 31, 2019 are as follows:

	2020		2019
(In $ millions)	Fair Value	Carrying  Value	Fair Value	Carrying  Value
Assets
Cash and cash equivalents	362.0	362.0	560.0	560.0
Restricted cash	16.4	16.4	—	—
Liabilities
Term Loan B	380.3	2,727.1	1,300.5	2,595.9
Other external debt facilities	—	—	269.7	282.3

Level 1

The carrying value of cash and cash equivalents and restricted cash, which are highly liquid, is a reasonable estimate of fair value.

As at December 31, 2020, we had loans under the Term Loan B with a carrying value of $2,727.1 million, all of which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets. As at December 31, 2020 and as at December 31, 2019 the Term B loan was freely tradable and its fair value was set equal to the price at which they were traded on this date.

Level 2

Loans under other external debt facilities relate to the West Vela facility (previously the $1,450 million Senior Secured Credit Facility), West Polaris facility, Tender Rig facility (previously the $440 million Rig Financing Agreement) and the West Vencedor facility. These loans are not freely tradable.

The debt facilities were fully repaid in 2020 and not included in the table above for year ending December 31, 2020. For the year ended December 31, 2019 the fair value was determined using of the current and long-term portion of these debt facilities was derived using a discounted cash flow model, using a cost of debt of 11.16%, with reference to the expected contractual repayments under the agreements. Refer to Note 16 - "Debt" for further information.

Financial instruments measured at fair value on a recurring basis

As at December 31, 2019, the fair values of interest rate swap contracts of $17.7 million were calculated using well-established independent valuation techniques, applied to contracted cash flows and expected future LIBOR interest rates, and counterparty non-performance credit risk assumptions as that date. The calculation of the credit risk in the swap values were subject to a number of assumptions including an assumed Credit Default Swap rate based on the Company's traded debt, plus a curve profile and recovery rate. These items were level 2 on the fair value hierarchy.

In 2019, the fair value of the related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris of $31.5 million was estimated based on discounted future cash flows. These liabilities were considered to be at estimated market rates. These have been categorized at level 2 on the fair value measurement hierarchy.

As at December 31, 2020, we had $20.8 million of interest rate swaps and $2.8 million of related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris, all of which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets at the expected value of the allowable claim. The interest rate swaps balance reflects the terminated value as at November 23, 2020 following the decision that was made to default on payments in preparation for Chapter 11 filing. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings".

Fair value considerations on non-recurring transactions

Certain of our assets and liabilities are required to be measured at fair value on a nonrecurring basis in accordance with U.S. GAAP. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. Refer to Note 10 - "Impairment of long-lived assets" for details of impairment charges relating to our drilling units, which were measured at fair value on a nonrecurring basis in 2020 and have presented the aggregate loss in “Impairment of long-lived assets” in our Consolidated Statements of Operations for the year ended December 31, 2020.

The assets measured at estimated fair value as of December 31, 2020 are as follows:

	2020
(In $ millions)	Fair Value	Carrying  Value
Assets
Drilling units	428.3	428.3

Level 3

The drilling units were impaired during the first and fourth quarters of 2020. We estimated the fair values of the impaired drilling units using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. These calculations utilized significant unobservable inputs, including management’s assumptions related to long-term future dayrates, contract probabilities, long-term economic utilization, capital and operating expenditures, reactivation costs and timing for the cold stacked rigs, recycling probabilities, applicable tax rates and asset lives. Our fair value estimates were representative of Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used.

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Commitments and contingencies

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

Legal Proceedings

From time to time the Company is a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with its acquisition or disposal activities. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2020.

West Leo

We received notification of a force majeure occurrence on October 1, 2016 in respect of the West Leo which was operating for Tullow Ghana Limited ("Tullow") in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience. We did not accept that the contract had been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract had been discharged by frustration. Accordingly, we amended our claim in the English High Court to reflect this.

On July 3, 2018 the English High Court ruled the case in our favor and we recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "other revenues" per our Consolidated Statements of Operations. See Note 8 - "Other revenues" for further details.

Patent infringement

In January 2015, a subsidiary of Transocean Ltd. filed suit (the "Suit") against certain of our subsidiaries for patent infringement. The Suit alleged that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.

In December 2018, we reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean for the dual activity drilling method on our rigs covering alleged past infringements and future use.

BP arbitration

In 2019, an arbitration entitled Seadrill US Gulf LLC, Seadrill Gulf Operations Vela LLC, and Seadrill Gulf Operations Auriga, LLC v. BP Exploration & Production, Inc., ICDR Case No. 01-19-003-0191 (the “Arbitration”), which was commenced by Seadrill US Gulf LLC, Seadrill Gulf Operations Vela, LLC, and Seadrill Gulf Operations Auriga LLC (collectively, the “Arbitration Debtors”) against BP Exploration & Production, Inc. (“BP”) and is currently pending before a three-arbitrator tribunal appointed by the International Centre for Dispute Resolution (the “Tribunal”), an affiliate of the American Arbitration Association (“AAA”). The Arbitration involves breach of contract claims against BP. BP has not asserted any counterclaims against the Arbitration Debtors.

The Arbitration Debtors and BP are parties to long-term contracts (the “Contracts”) worth $4.4 billion under which the Arbitration Debtors provided drilling rigs to BP. The Arbitration involves a dispute over the meaning of change-in-law provisions contained in the Contracts (the “Change-in-Law Provisions”). The Arbitration Debtors seek a total of $51 million for BP’s refusal to fully compensate their increased U.S. federal income tax costs incurred pursuant to the 2017 enactment of a Base Erosion Anti-Abuse Tax (“BEAT”).

Base erosion and anti-abuse tax (BEAT)

We continue to recognize income tax expense related to a provision of the 2017 US tax reform commonly referred to as BEAT. Three US drilling contracts include a change in legislation provision we believe makes the BEAT liability reimbursable. In September 2019 the Seadrill contracting parties commenced arbitration proceedings in New York for all three rigs to enforce these contractual obligations. A final hearing in the arbitration was held in March 2021 and a decision from the arbitration panel is expected in the first half of 2021.

Nigerian Cabotage Act litigation

Seadrill Mobile Units Nigeria Ltd ("SMUNL") commenced proceedings in May 2016 against the Honourable Minister for Transportation, the Attorney General of the Federation and the Nigerian Maritime Administration and Safety Agency with respect to interpretation of the Coastal and Inland Shipping (Cabotage) Act 2003 (the "Act"). On June 28, 2019, the Federal High Court of Nigeria delivered a judgement finding that: (1) Drilling operations fall within the definition of "Coastal Trade" or "Cabotage" under the Act and (2) Drilling Rigs fall within the definition of "Vessels" under the Act. The impact of this decision is that the Nigerian Maritime Administration and Safety Agency ("NIMASA") may impose a 2% surcharge on contract revenue from offshore drilling operations in Nigeria as well as requiring SMUNL register for Cabotage with NIMASA and pay all fees and tariffs as may be published in the guidelines that may be issued by the Minister of Transportation in accordance with the Act. However, on 22 July, 2019, SMUNL filed an appeal to the Court of Appeal challenging the decision of the Federal High Court. Due to the volume of cases currently being handled by the Court of Appeal sitting in Lagos we anticipate a decision within three to five years.

Although we intend to strongly pursue this appeal, we cannot predict the outcome of this case. We do not believe that it is probable that the ultimate liability, if any, resulting from this litigation will have a material effect on our financial position. Accordingly, no loss contingency has been recognized within the Consolidated Financial Statements.

Other claims or legal proceedings

We are not aware of any other legal proceedings or claims that we expect to have, individually or in the aggregate, a material adverse effect on the Company.

Commitments

We had no material lease commitments or unconditional purchase obligations at December 31, 2020 and 2019.

Guarantees

We have issued performance guarantees under our bank guarantee facility with Danske Bank in favor of third parties as beneficiaries totaling $11.9 million. As of December 31, 2020 we have not recognized any liabilities for these guarantees, as we do not consider it is probable for the guarantees to be called.

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Earnings per unit and cash distributions

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Earnings per unit and cash distributions

Earnings per unit and cash distributions

The below table sets out the calculation of (loss)/earnings per unit for each of periods presented in this report.

(in $ millions, except per unit data)	2020		2019		2018
Net (loss)/income attributable to:
Common unitholders	(2,091.3)		(76.2)		56.1
Subordinated unitholders	(459.6)		(16.7)		—
Net (loss)/income attributable to Seadrill Partners LLC owners	(2,550.9)		(92.9)		56.1
Weighted average units outstanding (in thousands):
Common unitholders	7,528		7,528		7,528		*
Subordinated unitholders	1,654		1,654		1,654		*
(Loss)/Earnings per unit:
Common unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	$	7.45	*
Subordinated unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	—
Cash distributions declared and paid in the period per unit (1) (2)	$	—	$	0.22	$	4.00	*
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):	$	—	$	—	$	0.01	*

* These amounts have been updated to reflect the 1 for 10 reverse stock split on July 2, 2019.

(1) Refers to the cash distributions declared and paid during the prior years.

(2) Distributions were declared and paid only with respect to the common units in 2019 and 2018.

(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.

Earnings per unit is calculated using the two-class method where undistributed earnings are allocated to the various member interests. The net income attributable to the common and subordinated unitholders and the holders of the incentive distribution rights is calculated as if all net income was distributed according to the terms of the distribution guidelines set forth in the Operating Agreement, regardless of whether those earnings could be distributed. The Operating Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of the quarter after establishment of cash reserves determined by the Company's Board of Directors to provide for the proper conduct of the Company's business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Therefore, the earnings per unit is not indicative of potential cash distributions that may be made based on historic or future earnings. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains/(losses).

Under the Operating Agreement, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $3.8750 per unit per quarter, plus any arrearages in the payment of minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

Distributions of available cash from operating surplus are to be made in the following manner for any quarter during the subordination period:

•First, to the common unitholders, pro-rata, until the Company distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•Second, to the common unitholders, pro-rata, until the Company distributes for each outstanding common an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters during the subordination period; and

•Third, to the subordinated units, pro-rata, the Company distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.

In addition, the Seadrill Member currently holds all of the incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of the quarterly distributions of cash available from operating surplus after the minimum quarterly distribution and target distribution levels have been achieved.

If for any quarter during the subordination period:

•The Company has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•The Company has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

The Company will then distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of the incentive distributions rights in the following manner:

•first, 100.0% to all unitholders, until each unitholder receives a total of $4.456 per unit for that quarter (the "first target distribution");

•second, 85.0% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $4.844 per unit for that quarter (the "second target distribution");

•third, 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $5.813 per unit for that quarter (the "third target distribution"); and

•thereafter, 50.0% to all unitholders, and 50.0% to the holders of the incentive distribution rights, pro rata.

The percentage interests set forth above assumes that the Company does not issue additional classes of equity securities.

The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:

•distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•the "adjusted operating surplus" (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and

•there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.

In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by the conflicts committee, the holder or holders of a majority of the subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.

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Supplementary cash flow information

12 Months Ended

Dec. 31, 2020

Supplemental Cash Flow Elements [Abstract]

Supplementary cash flow information

Supplementary cash flow information

The table below summarizes the non-cash investing and financing activities relating to the periods presented:

(In $ millions)	2020	2019	2018
Non-cash financing activities
Recognition of super senior loan and related fees (1)	141.5	—	—
Reclassification of prepaid advisory fees (2)	19.8	—	—

(1) In the year ended December 31, 2020, unpaid TLB interest of $87 million was converted into a super senior loan, carrying a $40 million commitment fee, $13.3 million exit fee and $1.2 million compounded interest. For more information refer to Note 16 – "Debt".

(2) $19.8 million prepaid refinancing advisory fees incurred up until July 2020 were reclassified from prepaid expenses to loan fees.

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Subsequent events

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Subsequent events

Subsequent events

Management Agreements

On February 3, 2021 the Company entered into a management agreement with Energy Drilling to maintain, market and operate our owned tender rigs T-15, T-16, and West Vencedor. The agreement started a 90-day transition period of services provided from Seadrill Limited to Energy Drilling.

On February 10, 2021 the Company submitted a motion for approval of a new framework agreement with Vantage Drilling for the management of certain rigs in our fleet. Following the execution of the Vantage Drilling management services agreement, the Debtors continued to receive proposals with respect to the operation of their floater vessels. Because the Vantage Drilling management services agreement remained subject to Bankruptcy Court approval (and was therefore not binding upon the Debtors), the Debtors undertook to assess such alternative proposals. Upon assessing the alternative proposals, the Debtors determined that the commercial proposition served by using a combination of Vantage Drilling, Diamond Offshore Drilling Inc. (“Diamond”), and Odfjell Drilling Ltd. (“Odjfell”), each as managers of certain of the Debtors’ floater vessels, was superior to the original Vantage Drilling management structure. Therefore, on March 16, 2021, the Debtors filed a supplement to the motion seeking approval of management services agreements with Vantage Drilling, Diamond, and Odjfell. On March 18, 2021, the Bankruptcy Court approved the motion, authorizing the Debtors to enter into management services agreements with Diamond, Odfjell, and an amended management services agreement with Vantage Drilling.

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Accounting policies (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Basis of presentation

Basis of presentation

The Consolidated Financial Statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States Dollars ("U.S. Dollars" or "US$") rounded to the nearest million, unless otherwise stated.

Basis of consolidation

Basis of consolidation

The financial statements include the results and financial position of all companies in which we directly or indirectly hold more than 50% of the voting control. We eliminate all intercompany balances and transactions.

We control Seadrill Operating LP and its majority owned subsidiaries as well as Seadrill Capricorn Holdings LLC and its majority owned subsidiaries. We separately present within equity on our Consolidated Balance Sheets the ownership interests attributable to parties with non-controlling interests in our Consolidated subsidiaries, and we separately present net income attributable to such parties in our Consolidated Statements of Operations.

Bankruptcy accounting

Bankruptcy accounting

Seadrill Partners LLC and certain of its direct and indirect consolidated subsidiaries (the “Debtors”) filed voluntary petitions on December 1, 2020 (the "Petition Date") to commence prearranged reorganization proceedings under Chapter 11 of Title 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the Southern District of Texas (the “Bankruptcy Court”) case number 20-35740. During the pendency of the

Chapter 11 proceedings, the Debtors will operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provision of the Bankruptcy Code. For further information refer to Note 4 - "Chapter 11 Proceedings".Since the Petition Date, we prepared our Consolidated Financial Statements under Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 requires that the financial statements, for periods subsequent to filing bankruptcy petitions, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net" on the Company’s Consolidated Statements of Operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the Consolidated Balance Sheets, particularly liabilities. Pre-petition obligations that may have been impacted by Chapter 11 reorganization process were classified on the Consolidated Balance Sheets within "Liabilities subject to compromise".

Allowance for credit losses

Allowance for credit losses

We adopted accounting standard update 2016-13 Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The new guidance replaces the “incurred loss” model required under the previous guidance with a current “expected credit loss” (or CECL) model. The CECL model requires recognition of expected credit losses over the life of a financial asset upon its initial recognition. Comparative periods are presented under the previous guidance with an allowance against a receivable balance recognized only if it was probable that we would not recover the full amount due to us. We determined doubtful accounts on a case-by-case basis and considered the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. The CECL model applies to external trade receivables, related party receivables and other financial assets measured at amortized cost. We have determined that on transition and at December 31, 2020, the impact of the CECL model is not material and no credit loss adjustments have been applied.

The CECL model contemplates a broader range of information to estimate expected credit losses over the contractual lifetime of an asset. It also requires to consider the risk of loss even if it is remote. We estimate expected credit losses based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts of events which may affect the collectability. We estimate the CECL allowance using a “probability-of-default” model, calculated by multiplying the exposure at default by the probability of default by the loss given default by a risk overlay multiplier over the life of the financial instrument (as defined by ASU 2016-13).

Revenues

Revenue from contracts with customers

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract with a customer. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments of service.

We recognize revenues for activities that correspond to a distinct time increment of service within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment of service, ratably over the estimated contract term.

We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required. Refer to Note 6 - "Revenue from contracts with customers".

Dayrate drilling revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment service it relates to. Revenue is recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract. The associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.

Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional

contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as "reimbursable revenues" in our Consolidated Statements of Operations.

Local Taxes - In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.

Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.

Other revenues

Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 8 - ''Other revenues''. Revenue is recognized as the performance obligation is satisfied, which on our leased rigs is on a straight-line basis.

Related party revenues - Related party revenues relate to onshore support and offshore personnel provided to Seadrill.

Early termination fees - Other revenues also include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved. Refer to Note 19 - ''Related party transactions''.

Vessel and rig operating expenses

Vessel and rig operating expenses

Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.

Mobilization and demobilization expenses

Mobilization and demobilization expenses

We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see "Deferred Contract Costs" above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.

We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract.

Repairs, maintenance and periodic surveys

Repairs, maintenance and periodic surveys

Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.

Income taxes

Income taxes

Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Refer to Note 7 – "Taxation".

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits.

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. We recognize the income tax effects of intercompany sales or

transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period of sale or transfer occurs.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as at the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Foreign currencies

Foreign currencies

The majority of our revenues and expenses are denominated in U.S. Dollars and therefore the majority of our subsidiaries use U.S. Dollars as their functional currency. Our reporting currency is also U.S. Dollars. For subsidiaries that maintain their accounts in currencies other than U.S. Dollars, we use the current method of translation whereby the Statements of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in members' capital.

Transactions in foreign currencies are translated into U.S. Dollars at the rates of exchange in effect at the date of the transaction. Foreign currency denominated monetary assets and liabilities are remeasured using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the Consolidated Statements of Operations.

Earnings Per Unit

Earnings Per Unit ("EPU")

We compute EPU using the two-class method set out in GAAP. We first allocate undistributed earnings for the period to the holders of common units, subordinated units and incentive distribution rights. This allocation is made in accordance with the cash distribution provisions contained in our First Amended and Restated Operating Agreement of the Company (the "Operating Agreement"). Unallocated earnings may be negative if amounts distributed are higher than total earnings. We allocate such deficits using the same cash distribution model.

We calculate the EPU for each category of units by taking the sum of the distributions to those units plus the allocation of those units undistributed earnings for the period and dividing this total by the weighted average number of units outstanding for the period. We don't have any potentially dilutive instruments and therefore don't present a diluted EPU. Refer to Note 23 - ''Earnings per unit and cash distributions''.

Fair value measurements

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. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets. Hierarchy Level 2 inputs are 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. Hierarchy Level 3 inputs are significant unobservable inputs, including those that require considerable judgment for which there is little or no market data. 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.

Current and non-current classification

Current and non-current classification

Generally, assets and liabilities (excluding deferred taxes and liabilities subject to compromise) are classified as current assets and liabilities respectively if their maturity is within one year of the balance sheet date. In addition, we classify any derivative financial instruments whose fair value is a net liability as current. Current liabilities will include where amounts from lenders are payable on demand at their discretion due to event of default clauses being met.

Generally, assets and liabilities are classified as non-current assets and liabilities respectively, if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivative financial instruments whose fair value is a net asset as non-current.

Where the liabilities are subject to compromise as part of the Chapter 11 proceedings they are classified separately in the Consolidated Balance Sheet and neither classified as current or non-current.

Cash and cash equivalents

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with maturities of three months or less. Amounts are presented net of allowances for credit losses.

Restricted cash consists of bank deposits which are subject to restrictions due to legislation, regulation or contractual arrangements. Restricted cash amounts that are expected to be used after one year from balance sheet date are classified as non-current assets. Amounts are presented

net of allowances for credit losses, which are assessed based on consideration of whether the balances have short-term maturities and whether the counterparty has an investment grade credit rating, limiting any credit exposure. Refer to Note 12 – "Restricted cash".

Receivables

Receivables

Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount net of expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 13 - ''Accounts receivable''.

Contract assets and liabilities

Contract assets and liabilities

Accounts receivables are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. If we recognize revenue ahead of this point, we also recognize a contract asset. Contract assets balances relate primarily to demobilization revenues recognized during the period but are contingent on future demobilization activities.

Contract liabilities include payments received for mobilization, rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

Related parties

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. Amounts receivable from related parties are presented net of allowances for expected credit losses and write-offs. Interest income on receivables is recognized as earned. Refer to Note 19 - ''Related party transactions'' for details of balances and material transactions with related parties.

Use of estimates

Use of estimates

Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

In assessing the recoverability of our drilling units carrying amounts, we make assumptions regarding estimated future cash flows, estimates in respect of residual value, day rates, drilling unit operating expenses and overhaul requirements.

Business combinations

Business combinations

We apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred.

Drilling units

Drilling units

Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up rigs, when new, is 30 years. The direct and incremental costs of significant capital projects, such as rig upgrades and reactivation projects, are capitalized and depreciated over the remaining life of the asset.

Drilling units acquired in a business combination are measured at fair value at the date of acquisition. Drilling units were also remeasured to fair value when we applied fresh start accounting at the date of emergence. Cost of property and equipment sold or retired, with the related accumulated depreciation and impairment is removed from the Consolidated Balance Sheet, and resulting gains or losses are included in the Consolidated Statement of Operations.

We re-assess the remaining useful lives of our drilling units when events occur which may impact our assessment of their remaining useful lives. These include changes in the operating condition or functional capability of our rigs, technological advances, changes in market and economic conditions as well as changes in laws or regulations affecting the drilling industry.

Assets held for sale and Impairment of long-lived assets

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: management commits to a plan to sell the asset (disposal group), the asset is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets, an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset is probable, and transfer of the asset is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to be generated from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, we then compare the carrying value of the asset with the discounted future net cash flows, using a relevant weighted-average cost of capital. The impairment loss to be recognized during the period, is the amount by which the carrying value of the asset exceeds the discounted future net cash flows.

Favorable drilling contracts - intangible assets

Favorable drilling contracts - intangible assets Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the Consolidated Statements of Operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.

Derivative Financial Instruments and Hedging Activities

Derivative Financial Instruments and Hedging Activities

Our derivative financial instruments are measured at fair value and are not designated as hedging instruments. Changes in their fair value are recorded as a gain or loss as a separate line item within "financial items" in the Consolidated Statements of Operations. We classify the asset or liability for derivative financial instruments within "other current assets" or "other current liabilities" in our Consolidated Balance Sheets. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements. Refer to Note 21 - ''Fair Value Measurement''.

Trade payables

Trade payablesTrade payables are liabilities to a supplier for a good or service provided to us.

Deferred charges

Deferred chargesLoan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in "interest expense" in the Consolidated Statement of Operations.

Debt

DebtWe have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid.

Loss contingencies

Loss contingencies

We recognize a loss contingency in the Consolidated Balance Sheets where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Refer to Note 22 - ''Commitments and contingencies''.

Equity allocation

Equity allocation

Earnings and losses attributable to unitholders of Seadrill Partners are allocated to all unitholders on a pro rata basis for the purposes of presentation in the Consolidated Statements of Changes in Members' Capital. Earnings and losses attributable to unitholders for any period are first reduced for any cash distributions for the period to be paid to the holders of the incentive distribution rights.

At the time of the Company's initial public offering, the equity attributable to unitholders was allocated using the hypothetical amounts which would be distributed to the various unitholders on a liquidation of the Company ("hypothetical liquidation method"). This method has also been used to account for issuances of common units by the Company, and the deemed distributions from equity which resulted from acquisitions of drilling units from Seadrill.

Guarantees

Guarantees

Guarantees issued by us, excluding those that are guaranteeing our own performance, are recognized at fair value at the time that the guarantees are issued and reported in "other current liabilities" and "other non-current liabilities" in our Consolidated Balance Sheets. If it becomes probable that we will have to perform under a guarantee, we remeasure the liability if the amount of the loss can be reasonably estimated. The recognition of fair value is not required for certain guarantees such as the parent's guarantee of a subsidiary's debt to a third party. Financial guarantees written are assessed for credit losses and any allowance is presented as a liability for off-balance sheet credit exposures where the balance exceeds the collateral provided over the remaining instrument life. The allowance is assessed at the individual guarantee level, calculated by multiplying the balance exposed on default by the probability of default and loss given default over the term of the guarantee.

Recent accounting standards

Recent accounting standards

We adopted the following accounting standard updates ("ASUs") in the year:

a) ASU 2016-13 - Financial Instruments - Measurement of Credit Losses (Also 2018-19, 2019-04 & 2019-11)

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and subsequent amendments, including ASU 2018-19, ASU 2019-04 and ASU 2019-11: Codification Improvements to Topic 326 ‘‘Financial Instruments-Credit Losses”. Topic 326 replaces the incurred loss impairment methodology (that recognizes losses when a probable threshold is met) with a requirement to recognize lifetime expected credit losses (measured over the contractual life of the instrument) immediately, based on information about past events, current conditions and forecasts of future economic conditions. Under the current expected credit loss ( the "CECL") measurement financial assets are reflected at the net amount expected to be collected from the financial asset, CECL measurement is applicable to financial assets measured at amortized cost as well as off-balance sheet credit exposures not accounted for as insurance (including financial guarantees).

Using the modified retrospective method, reporting periods beginning after January 1, 2020 are presented under Topic 326 while comparative periods continue to be reported in accordance with previously applicable GAAP and have not been restated. The adoption of Topic 326 did not have a material impact on our condensed consolidated financial statements.

b) ASU 2020-03 Financial Instruments: Codification Improvements

In March 2020, the FASB issued ASU 2020-03 Financial Instruments (Topic 825) - Codification Improvements. The amendments in this ASU propose seven clarifications to improve the understandability of existing guidance, including that fees between debtor and creditor and third-party costs directly related to exchanges or modifications of debt instruments include line-of-credit or revolving debt arrangements. We adopted the codification improvements that were effective on issuance from January 1, 2020 under the specified transition approach connected with each of the codification improvements. This amendment has not had a material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2020.

c) Other accounting standard updates

We additionally adopted the following accounting standard updates in the year which did not have any material impact on our Consolidated Financial Statements and related disclosures:

•ASU 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.

•ASU 2018-13 Fair Value Measurement: Changes to the Disclosure Requirements for Fair Value Measurement.

•ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans.

•ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.

•ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities.

•ASU 2019-04 Codification Improvements to Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments.

•ASU 2019-08 Compensation—Stock Compensation (Topic 718) and Revenue from Contracts with Customers (Topic 606): Codification Improvements—Share-Based Consideration Payable to a Customer.

2) Recently issued accounting standards

Recently issued ASUs by the FASB that we have not yet adopted but which could affect our Consolidated Financial Statements and related disclosures in future periods:

a) ASU 2019-12 Income Taxes (Topic 740): Simplifying the accounting for income taxes

In December 2019, the FASB issued ASU 2019-12. The amendments in this update simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The guidance will be effective from January 1, 2021 on a mainly prospective basis, with early adoption permitted. This amendment will have no material impact on our consolidated financial statements or related disclosures, including retained earnings, as of January 1, 2021.

b) ASU 2020-04 Reference Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04. The amendments provide temporary optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The applicable expedients for us are in relation to modifications of contracts within the scope of Topics 310, Receivables, 470, Debt, and 842, Leases. This optional guidance may be applied prospectively from any date beginning March 12, 2020 and cannot be applied to contract modifications that occur after December 31, 2022. We are in the process of evaluating the impact of this standard update on our consolidated financial statements and related disclosures.

c) Other accounting standard updates issued by the FASB

As of April 30, 2021, the FASB have issued several further updates not included above. We do not currently expect any of these updates to affect our Consolidated Financial Statements and related disclosures either on transition or in future periods.

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Chapter 11 Proceedings (Tables)

12 Months Ended

Dec. 31, 2020

Reorganizations [Abstract]

Liabilities subject to compromise

Liabilities subject to compromise, as presented on the Consolidated Balance Sheet as at December 31, 2020, include the following:

(In $ millions)	2020
Senior undersecured or impaired external debt	2,727.1
Derivatives previously recorded at fair value	20.8
Accounts payable and other liabilities	24.4
Accrued interest payable	32.5
Amount due to related party	74.3
Liabilities subject to compromise	2,879.1

Reorganization items, net

The following table summarizes reorganization items:

(In $ millions)	2020
Advisory and professional fees	7.1
Unamortized debt issuance costs	42.9
Interest income on surplus cash invested	(0.2)
Reorganization items, net	49.8

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Segment information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of contract revenue split by customer

A breakdown of our revenues by customer for the years ended December 31, 2020, 2019 and 2018 is as follows: 

	2020		2019		2018
BP	75.8	%	67.6	%	68.0	%
Reliance	8.6	%	—	%	—	%
ExxonMobil	8.3	%	11.0	%	0.3	%
Petronas	5.5	%	9.9	%	—	%
Chevron	—	%	7.2	%	8.5	%
Tullow	—	%	—	%	19.8	%
Other	1.8	%	4.3	%	3.4	%
Total	100	%	100	%	100	%

Company's revenues and fixed assets by geographic area

The following presents the revenues for the years ended December 31, 2020, 2019 and 2018 and fixed assets as of December 31, 2020 and 2019 by geographic area:

Revenues

(In $ millions)	2020	2019	2018
United States	409.4	539.1	618.1
India	46.0	—	—
Canada	45.2	60.9	85.3
Malaysia	36.9	40.1	—
Thailand	0.2	53.8	88.7
Gabon	0.2	21.2	—
Myanmar	—	17.8	—
Ghana	—	—	205.5
Other	0.2	17.1	40.6
Total	538.1	750.0	1,038.2

Fixed Assets—Drilling Units (1)  

(In $ millions)	2020	2019
United States	153.8	2,561.7
Malaysia	88.2	607.1
India	53.9	—
Canada	53.8	451.7
Aruba	51.5	—
Singapore	27.1	108.8
Namibia	—	502.5
Norway	—	499.2
Thailand	—	109.8
Total	428.3	4,840.8

(1)The fixed assets referred to in the table above include the 11 drilling units at December 31, 2020 and December 31, 2019. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

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Revenue from contracts with customers (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Schedule of receivables and contract liabilities from contracts with customers, and significant changes in the contract liabilities

The following table provides information about receivables and contract liabilities from our contracts with customers:

(In $ millions)	2020	2019
Accounts receivable, net	56.6	146.7
Current contract liabilities (deferred revenues) (1)	0.9	3.0

(1)  Current contract liabilities balances are included in "other current liabilities" in our Consolidated Balance Sheets as at December 31, 2020.

Significant changes in the contract liabilities balances during the year ended December 31, 2020 are as follows:

(In $ millions)	2020	2019
Contract liabilities at start of period	3.0	6.4
Decrease due to amortization of revenue that was included in the beginning contract liability balance	(3.0)	(9.3)
Increase due to cash received, excluding amounts recognized as revenue	0.9	5.9
Contract liabilities at end of period	0.9	3.0

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Taxation (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Components of provision for income taxes

Income taxes consist of the following:

(In $ millions)	2020	2019	2018
Current tax expense / (benefit):
U.K.	—	—	(0.3)
Foreign	28.3	(39.3)	86.3
Total current tax expense / (benefit)	28.3	(39.3)	86.0
Deferred tax expense / (benefit):
Foreign	1.7	3.2	0.7
Total income tax expense / (benefit)	30.0	(36.1)	86.7

Effective income tax rate reconciliation

The Company's effective income tax rate for each of the years ended on December 31, 2020, 2019 and 2018 differs from the U.K. statutory income tax rate as follows:

	2020		2019		2018
U.K. statutory income tax rate	19.0	%	19.0	%	19.0	%
Non-U.K. taxes	(19.7)	%	(2.8)	%	35.0	%
Effective income tax rate	(0.7)	%	16.2	%	54.0	%

Deferred tax assets and liabilities

Our deferred tax assets consist of the following:

(In $ millions)	2020	2019
Provisions	54.9	0.6
Net operating losses carry forward	221.5	77.5
Interest carry forward	—	29.6
Property, plant and equipment	174.5	—
Other	3.6	5.3
Gross deferred tax assets	454.5	113.0
Valuation allowance	(451.6)	(107.1)
Deferred tax asset, net of valuation allowance	2.9	5.9

Our deferred tax liabilities consist of the following:

(In $ millions)	2020	2019
Property, plant and equipment	—	0.1
Unremitted earnings of subsidiaries	0.6	1.7
Gross deferred tax liabilities	0.6	1.8
Net deferred tax asset	2.3	4.1

Unrecognized tax benefits schedule

The changes to the Company's balance related to unrecognized tax benefits were as follows:

(In $ millions)	2020	2019
Balance beginning of year	40.2	101.6
Increases as a result of positions taken in prior years	—	1.1
Decreases as a result of positions taken in prior years	(1.0)	(60.7)
Settlements	—	(1.8)
Unrecognized tax benefits	39.2	40.2

Tax examinations

The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:

Jurisdiction	Earliest Open Year
United States	2016
Nigeria	2012
Ghana	2013

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Other revenues (Tables)

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Other revenues

Other revenues comprise the following items: 

(In $ millions)	2020	2019	2018
Early termination revenue	—	41.0	204.9
Related party other revenues	1.1	1.8	4.6
Total	1.1	42.8	209.5

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Other operating items (Tables)

12 Months Ended

Dec. 31, 2020

Other Operating Gains (Losses) [Abstract]

Other operating items

Other operating items comprise the following: 

(In $ millions)	2020	2019	2018
Loss on impairment of goodwill	—	—	(3.2)
Revaluation of contingent consideration	—	0.7	—
Impairment of long-lived assets	(4,210.4)	—	—
Total	(4,210.4)	0.7	(3.2)

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Interest expense (Tables)

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Interest expense

Interest expense consists of the following:

(In $ millions)	2020	2019	2018
Interest on debt facilities (1)	189.2	246.3	245.3
Loan fee amortization (2)	44.2	12.3	12.7
Other (3)	1.9	3.9	5.7
Total interest expense	235.3	262.5	263.7

(1) We are charged interest on our debt facilities at rates explained in Note 16 - "Debt". As a result of filing for Chapter 11, no interest has been recognized from December 1, 2020. For further details refer to Note 4 - "Chapter 11 Proceedings".

(2) We incur loan fees on our debt facilities that are amortized over the term of the loan. The increase in 2020 is due to commitment and exit fees incurred on the new super senior loans. For further details refer to Note 16 - "Debt".

(3) Other interest expense primarily relates to the unwind of the discount on contingent consideration payable to Seadrill. For further details refer to Note 19 - "Related party transactions".

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Other assets (Tables)

12 Months Ended

Dec. 31, 2020

Other Assets [Abstract]

Other assets

Other assets include the following:

(In $ millions)	2020	2019
Intangible asset - Favorable contracts	—	40.4
Mobilization revenue receivables	—	22.3
Prepaid expenses	26.7	14.1
Income taxes receivable	13.0	19.3
VAT receivable	5.7	10.6
Deferred mobilization costs	3.0	7.5
Reimbursable amounts due from customers	1.5	3.5
Other	3.1	1.8
Total other assets	53.0	119.5

Other assets are presented in our Consolidated Balance Sheet as follows:

(In $ millions)	2020	2019
Other current assets	45.0	119.5
Other non-current assets (1)	8.0	—
Total other assets	53.0	119.5

(1) Relates to prepaid Directors and Officers insurance cover relating to tail back claims in the Chapter 11 process.

Favorable contracts

The gross carrying amounts and accumulated amortization included in "other current asset"' and "other non-current assets" in the Consolidated Balance Sheets were as follows:

	2020			2019
(In $ millions)	Gross carrying amount	Accumulated amortization	Net carrying amount	Gross carrying amount	Accumulated amortization	Net carrying amount
Intangible assets- Favorable contracts
Balance at beginning of period	357.3	(316.9)	40.4	357.3	(271.8)	85.5
Amortization of favorable contracts	—	(40.4)	(40.4)	—	(45.1)	(45.1)
Balance at end of period	357.3	(357.3)	—	357.3	(316.9)	40.4

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Drilling units (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Drilling units

The below table shows the gross value and net book value of our drilling units at December 31, 2020 and December 31, 2019.

(In $ millions)	Cost	Accumulated depreciation	Net Book Value
Opening balance as at January 1, 2019	6,714.0	(1,708.4)	5,005.6
Additions	111.1	—	111.1
Depreciation	—	(275.9)	(275.9)
Closing balance as at December 31, 2019	6,825.1	(1,984.3)	4,840.8
Additions	28.7	—	28.7
Impairment	(4,210.4)	—	(4,210.4)
Depreciation	—	(230.8)	(230.8)
Closing balance as at December 31, 2020	2,643.4	(2,215.1)	428.3

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Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt amounts outstanding

As at December 31, 2020 and December 31, 2019, we had the following debt amounts outstanding:

(In $ millions)	2020	2019
External debt agreements
Term Loan B	2,727.1	2,607.6
West Vela Facility	—	151.0
West Polaris Facility	—	114.9
Tender Rig Facility	—	18.6
Total external debt	2,727.1	2,892.1
Less: Debt balance held as subject to compromise	(2,727.1)	—
Debt balance not subject to compromise	—	2,892.1

Presentation of debt in balance sheet

The below tables show how the above balances are presented in the Consolidated Balance Sheets:

	Outstanding debt as at December 31, 2020
(In $ millions)	Principal outstanding	Debt Issuance Costs (1)	Total Debt
Debt held as subject to compromise	2,727.1	—	2,727.1
Total interest-bearing debt	2,727.1	—	2,727.1

	Outstanding debt as at December 31, 2019
(In $ millions)	Principal outstanding	Debt Issuance Costs	Total Debt
Debt due within twelve months	313.3	(11.9)	301.4
Long-term external debt	2,578.8	(2.0)	2,576.8
Total interest-bearing debt	2,892.1	(13.9)	2,878.2

(1) On filing for Chapter 11 on December 1, 2020 all unamortized debt issuance costs on under secured debt have been written off to "reorganization items, net" in our Consolidated Statement of Operations. For further details refer to Note 4 - "Chapter 11 Proceedings".

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Other liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Payables and Accruals [Abstract]

Other liabilities

Other liabilities are comprised of the following: 

(In $ millions)	2020	2019
Uncertain tax position	44.4	44.2
Accrued expenses	13.1	34.0
Taxes payable	31.8	35.1
Interest rate swap agreements (1)	—	17.7
Employee and business withheld taxes, social security and vacation payment	8.3	9.0
VAT payable	2.2	4.7
Deferred mobilization/demobilization revenues (see Note 6 - "Revenue from contracts with customers")	0.9	3.0
Total other liabilities (2)	100.7	147.7

Other liabilities are classified in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Other current liabilities	56.3	103.5
Other non-current liabilities	44.4	44.2
Total other liabilities (1)	100.7	147.7

(1) In preparation for Chapter 11 filing, a decision was made to default on the interest rate swap payments that were due on November 23, 2020. As a result, the outstanding derivative balance on this date was held at the counterparty claimed value within "liabilities subject to compromise" on our Consolidated Balance Sheets as at December 31, 2020. Refer to Note 20 - "Risk management and financial instruments" for more information.

(2) Balances held as at December 31, 2020 exclude liabilities that are subject to compromise, which have been reclassified to a separate line within the Consolidated Balance Sheet. This represents our estimate of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. For further information refer to Note 1 - "General information".

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Non-controlling interest (Tables)

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

Non-controlling interest

Changes in non-controlling interests for the periods presented in this report were as follows:

(In $ millions)	Non-controlling interest
December 31, 2018	1,384.5
Share of net loss allocated to the non-controlling interest	(94.3)
Cash distributions	(1.5)
December 31, 2019	1,288.7
Share of net loss allocated to the non-controlling interest	(2,038.0)
December 31, 2020	(749.3)

Our non-controlling interest consists of Seadrill Limited's 42% interest in Seadrill Operating LP and 49% interest in Seadrill Capricorn Holdings LLC. Of which, we hold the following:

(1) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Capricorn Holdings LLC owns 100% of the entities that own and operate the West Capricorn, West Sirius, West Auriga and West Vela.

(2) a 58% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through our 100% ownership of its general partner, Seadrill Operating GP LLC. Seadrill Operating LP owns: (a) 100% interest in the entities that own the West Aquarius, West Leo, West Polaris and the West Vencedor, (b) approximately 56% interest in Seadrill Deepwater Drillship that owns and operates the West Capella and (c) a 51% limited liability interest in Seadrill Mobile Units (Nigeria).

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Related party transactions (Tables)

12 Months Ended

Dec. 31, 2020

Related Party Transactions [Abstract]

Net expenses (income) and receivables (payables) from related party

The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2020, 2019 and 2018.

(In $ millions)	2020	2019	2018
Related party inventory sales (a)	1.1	1.8	3.2
Rig operating costs (b)	—	—	1.4
Total related party operating revenues	1.1	1.8	4.6
Management and technical support fees (c) (d)	60.1	70.5	70.6
Rig operating costs (e)	—	—	0.8
Related party inventory purchases (a)	1.4	1.1	0.7
Total related party operating expenses	61.5	71.6	72.1
Interest expense recognized on deferred contingent consideration (h)	(2.0)	(3.3)	(3.1)
Related party interest expense (f)	—	—	(1.4)
Total related party financial items	(2.0)	(3.3)	(4.5)

The below table provides a summary of amounts due to or from Seadrill at December 31, 2020 and December 31, 2019.

(In $ millions)	2020	2019
Trading balances due from Seadrill and subsidiaries (g)	7.6	6.9
Total related party receivables	7.6	6.9

(In $ millions)	2020	2019
Trading balances due to Seadrill and subsidiaries (g)	78.9	79.5
Deferred and contingent consideration to related party - short term portion (h)	2.8	31.5
Total related party payables	81.7	111.0
Less: Related party payables held as subject to compromise	(74.3)	—
Related party payables not subject to compromise	7.4	111.0

Chapter 11 proceedings

On filing for Chapter 11, our pre-petition related party payables are held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020. For further information on our bankruptcy proceedings refer to Note 4 - "Chapter 11 Proceedings" of our Consolidated Financial Statements included herein.

(a) Related party inventory sales and purchases

Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.

(b) Rig operating costs charged to Seadrill

Seadrill Partners has charged to Seadrill Limited, through its Nigerian service company, certain services including the provision of onshore and offshore personnel, which was provided for the West Jupiter drilling rig operating in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended in 2018.

(c) Management and administrative services agreement

Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged an allocation for these services on a cost plus mark-up basis. During the year ended December 31, 2020, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreements for certain rigs have been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(d) Operations and technical supervision agreements

In addition, certain subsidiaries of Seadrill Partners have advisory, technical and/or administrative services agreements with subsidiaries of Seadrill. An allocation of these services are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services. This agreements has been terminated after the year ended December 31, 2020. Refer to Note 25 - "Subsequent events" for further information.

(e) Rig operating costs charged by Seadrill

Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged an allocation for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%.

(f) Interest expense charged by Seadrill

Interest expense charged by Seadrill for the West Vencedor loan arrangement that was due to Seadrill. The loan was repaid during 2018.

(g) Trading balances

Receivables and payables with Seadrill Limited and its subsidiaries are comprised of management fees, advisory and administrative services, and certain other amounts due. Receivables and payables are generally settled quarterly in arrears for those balances that are not held as liabilities subject to compromise. Trading balances to Seadrill Partners and its subsidiaries are unsecured.

(h) Deferred consideration to related party

We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela remaining which is held within "liabilities subject to compromise" in our Consolidated Balance Sheets at December 31, 2020.

On the West Vela we are required to pay to Seadrill $42k per day for mobilization and a further $40k per day adjusted for utilization over the remaining contract term with BP, which completed in November 2020.

On the West Polaris we agreed to pay Seadrill 100% of dayrate earned above $450k per day for the remainder of the contract with ExxonMobil and 50% of the dayrate earned above $450k per day on any subsequent contract until March 2025. In the year ended December 31, 2019, following reductions in future dayrate estimates and re-contracting assumptions, we impaired the remaining value of the liability to a nil carrying value, resulting in a $0.7 million gain in the Consolidated Statement of Operations.

The below table sets out the fair value of the liabilities at December 31, 2020 and December 31, 2019.

(In $ millions)	2020	2019
West Vela
Mobilization due to Seadrill	2.8	17.2
Seadrill share of dayrate from BP contract	—	14.3
Total	2.8	31.5

These liabilities are presented in our Consolidated Balance Sheets as follows:

(In $ millions)	2020	2019
Current deferred and contingent consideration to related party	—	31.5
Liabilities subject to compromise	2.8	—
Total	2.8	31.5

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Risk management and financial instruments (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Interest rate swap and cross currency interest rate swap agreements

Our interest rate swap agreements as at November 23, 2020, were as follows:

Maturity date	Outstanding principal as at November 23, 2020		Receive rate	Pay rate
	(In $ millions)
February 21, 2021	2,714.1		3 month LIBOR	2.45% to 2.52%	(1) (2)
Total outstanding principal	$	2,714.1

(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.

(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.

Following the defaults on our debt and the termination of our derivatives in 2020 we no longer have any net exposure to short term fluctuations in interest rates. As at December 31, 2019, $156.3 million of our debt was exposed to interest rate fluctuations.

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Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Carrying value and estimated fair value of financial instruments

The carrying value and estimated fair value of our financial instruments that are measured at amortized cost as of December 31, 2020 and December 31, 2019 are as follows:

	2020		2019
(In $ millions)	Fair Value	Carrying  Value	Fair Value	Carrying  Value
Assets
Cash and cash equivalents	362.0	362.0	560.0	560.0
Restricted cash	16.4	16.4	—	—
Liabilities
Term Loan B	380.3	2,727.1	1,300.5	2,595.9
Other external debt facilities	—	—	269.7	282.3

Assets Measured at Estimated Fair Value, Non-Recurring

The assets measured at estimated fair value as of December 31, 2020 are as follows:

	2020
(In $ millions)	Fair Value	Carrying  Value
Assets
Drilling units	428.3	428.3

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Earnings per unit and cash distributions (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Calculations of loss/(earnings) per unit

The below table sets out the calculation of (loss)/earnings per unit for each of periods presented in this report.

(in $ millions, except per unit data)	2020		2019		2018
Net (loss)/income attributable to:
Common unitholders	(2,091.3)		(76.2)		56.1
Subordinated unitholders	(459.6)		(16.7)		—
Net (loss)/income attributable to Seadrill Partners LLC owners	(2,550.9)		(92.9)		56.1
Weighted average units outstanding (in thousands):
Common unitholders	7,528		7,528		7,528		*
Subordinated unitholders	1,654		1,654		1,654		*
(Loss)/Earnings per unit:
Common unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	$	7.45	*
Subordinated unitholders (U.S. Dollars)	$	(277.80)	$	(10.12)	—
Cash distributions declared and paid in the period per unit (1) (2)	$	—	$	0.22	$	4.00	*
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3):	$	—	$	—	$	0.01	*

* These amounts have been updated to reflect the 1 for 10 reverse stock split on July 2, 2019.

(1) Refers to the cash distributions declared and paid during the prior years.

(2) Distributions were declared and paid only with respect to the common units in 2019 and 2018.

(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.

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Supplementary cash flow information (Tables)

12 Months Ended

Dec. 31, 2020

Supplemental Cash Flow Elements [Abstract]

Non-cash investing and financing activities

The table below summarizes the non-cash investing and financing activities relating to the periods presented:

(In $ millions)	2020	2019	2018
Non-cash financing activities
Recognition of super senior loan and related fees (1)	141.5	—	—
Reclassification of prepaid advisory fees (2)	19.8	—	—

(1) In the year ended December 31, 2020, unpaid TLB interest of $87 million was converted into a super senior loan, carrying a $40 million commitment fee, $13.3 million exit fee and $1.2 million compounded interest. For more information refer to Note 16 – "Debt".

(2) $19.8 million prepaid refinancing advisory fees incurred up until July 2020 were reclassified from prepaid expenses to loan fees.

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General information (Details) $ in Millions	Feb. 12, 2021 USD ($)	Dec. 31, 2020 USD ($) drilling_unit	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
General Information [Line Items]
Number of drilling units owned and operated | drilling_unit		11
Senior undersecured or impaired external debt		$ 2,727.1	$ 0.0
Cash, cash equivalents, and restricted cash		378.4	560.0	$ 841.6	$ 848.6
Unrestricted cash and cash equivalents		$ 362.0	$ 560.0
Subsequent Event
General Information [Line Items]
Secured debt equitized	$ 2,700.0

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Accounting policies (Details)	12 Months Ended
	Dec. 31, 2020
Drilling units
Property, Plant and Equipment [Line Items]
Estimated economic useful life	30 years
Overhauls of drilling units
Property, Plant and Equipment [Line Items]
Estimated economic useful life	5 years

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Chapter 11 Proceedings (Liabilities subject to compromise) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Reorganizations [Abstract]
Senior undersecured or impaired external debt	$ 2,727.1	$ 0.0
Derivatives previously recorded at fair value	20.8
Accounts payable and other liabilities	24.4
Accrued interest payable	32.5
Amount due to related party	74.3
Liabilities subject to compromise	$ 2,879.1	$ 0.0

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Chapter 11 Proceedings (Narrative) (Details) $ in Millions		3 Months Ended	12 Months Ended
	Feb. 15, 2021 USD ($) claim	Apr. 30, 2021 claim	Dec. 31, 2020 USD ($)	Feb. 12, 2021 USD ($)
Reorganizations [Abstract]
Interest on liabilities subject to compromise			$ 21.3
Subsequent Event
Subsequent Event [Line Items]
Secured debt equitized				$ 2,700.0
Number of claims filed | claim	285	120
Amount of claims filed	$ 3,200.0

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Chapter 11 Proceedings (Schedule of Reorganization Items) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reorganizations [Abstract]
Advisory and professional fees	$ 7.1
Unamortized debt issuance costs	42.9
Interest income on surplus cash invested	(0.2)
Reorganization items, net	$ 49.8	$ 0.0	$ 0.0

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Segment information (Operating segment) (Details) - segment	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue, Major Customer [Line Items]
Number of operating segments	1
Customer Concentration Risk | Contract Revenues
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	100.00%	100.00%	100.00%
Customer Concentration Risk | Contract Revenues | BP
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	75.80%	67.60%	68.00%
Customer Concentration Risk | Contract Revenues | Reliance
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	8.60%	0.00%	0.00%
Customer Concentration Risk | Contract Revenues | ExxonMobil
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	8.30%	11.00%	0.30%
Customer Concentration Risk | Contract Revenues | Petronas
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	5.50%	9.90%	0.00%
Customer Concentration Risk | Contract Revenues | Chevron
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	0.00%	7.20%	8.50%
Customer Concentration Risk | Contract Revenues | Tullow
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	0.00%	0.00%	19.80%
Customer Concentration Risk | Contract Revenues | Other
Revenue, Major Customer [Line Items]
Revenue, major customer (as percent)	1.80%	4.30%	3.40%

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Segment information (Geographic data - Revenues) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 538.1	$ 750.0	$ 1,038.2
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	409.4	539.1	618.1
India
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	46.0	0.0	0.0
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	45.2	60.9	85.3
Malaysia
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	36.9	40.1	0.0
Thailand
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	0.2	53.8	88.7
Gabon
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	0.2	21.2	0.0
Myanmar
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	0.0	17.8	0.0
Ghana
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	0.0	0.0	205.5
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 0.2	$ 17.1	$ 40.6

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Segment information (Geographical data - Drilling units) (Details) $ in Millions	Dec. 31, 2020 USD ($) drilling_unit	Dec. 31, 2019 USD ($) drilling_unit
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	$ 428.3	$ 4,840.8
Number of drilling units | drilling_unit	11	11
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	$ 153.8	$ 2,561.7
Malaysia
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	88.2	607.1
India
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	53.9	0.0
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	53.8	451.7
Aruba
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	51.5	0.0
Singapore
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	27.1	108.8
Namibia
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	0.0	502.5
Norway
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	0.0	499.2
Thailand
Revenues from External Customers and Long-Lived Assets [Line Items]
Fixed assets - drilling rigs	$ 0.0	$ 109.8

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Revenue from contracts with customers - Receivables and Contract Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 56.6	$ 146.7
Current contract liabilities (deferred revenues)	$ 0.9	$ 3.0

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Revenue from contracts with customers - Significant Changes in Contract Liabilities (Details) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in Contract with Customer, Liability [Roll Forward]
Contract liabilities at start of period	$ 3.0	$ 6.4
Decrease due to amortization of revenue that was included in the beginning contract liability balance	(3.0)	(9.3)
Increase due to cash received, excluding amounts recognized as revenue	0.9	5.9
Contract liabilities at end of period	$ 0.9	$ 3.0

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Taxation (Components of income taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current tax expense / (benefit):
U.K.	$ 0.0	$ 0.0	$ (0.3)
Foreign	28.3	(39.3)	86.3
Total current tax expense / (benefit)	28.3	(39.3)	86.0
Deferred tax expense / (benefit):
Foreign	1.7	3.2	0.7
Total income tax expense / (benefit)	$ 30.0	$ (36.1)	$ 86.7
Effective income tax rate reconciliation [Abstract]
U.K. statutory income tax rate	19.00%	19.00%	19.00%
Non-U.K. taxes	(19.70%)	(2.80%)	35.00%
Effective income tax rate	(0.70%)	16.20%	54.00%

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Taxation (Net deferred taxes) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Provisions	$ 54.9	$ 0.6
Net operating losses carry forward	221.5	77.5
Interest carry forward	0.0	29.6
Property, plant and equipment	174.5	0.0
Other	3.6	5.3
Gross deferred tax assets	454.5	113.0
Valuation allowance	(451.6)	(107.1)
Deferred tax asset, net of valuation allowance	2.9	5.9
Property, plant and equipment	0.0	0.1
Unremitted earnings of subsidiaries	0.6	1.7
Gross deferred tax liabilities	0.6	1.8
Net deferred tax asset	$ 2.3	$ 4.1

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Taxation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Examination [Line Items]
CARES Act, income tax benefit	$ 6.0
Net operating losses carry forward	221.5	$ 77.5
Net operating loss carry forward, not subject to expiration	51.9
Net operating loss carry forward, subject to expiration	169.6
Net operating losses carryforward, attributable to impairment	218.9
Deferred tax assets, property and equipment, attributable to impairment	174.5
Valuation allowance	451.6	107.1
Uncertain tax position	39.2	40.2	$ 101.6
Unrecognized tax benefits, accrued interest and penalties	5.2	4.0
Unrecognized tax benefits, interest and penalty expense/(benefit)	1.2	$ (12.4)	$ 8.4
Unrecognized tax benefits, amount would have favorable impact if recognized	44.4
Net operating losses carry forward
Income Tax Examination [Line Items]
Valuation allowance	220.7
Property and equipment
Income Tax Examination [Line Items]
Valuation allowance	174.7
Interest carry forward
Income Tax Examination [Line Items]
Valuation allowance	$ 55.4

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Taxation (Uncertain tax positions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Unrecognized Tax Benefits
Balance beginning of year	$ 40.2	$ 101.6
Increases as a result of positions taken in prior years	0.0	1.1
Decreases as a result of positions taken in prior years	(1.0)	(60.7)
Settlements	0.0	(1.8)
Unrecognized tax benefits	$ 39.2	$ 40.2

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Other revenues (Details) - Other revenues - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Early termination revenue		$ 0.0	$ 41.0	$ 204.9
Related party other revenues		1.1	1.8	4.6
Total	[1]	$ 1.1	$ 42.8	$ 209.5

[1] Includes transactions with related parties. Refer to Note 19 - "Related party transactions".

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Other operating items (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Operating Gains (Losses) [Abstract]
Loss on impairment of goodwill			$ 0.0	$ 0.0	$ (3.2)
Revaluation of contingent consideration			0.0	0.7	0.0
Impairment of long-lived assets	$ (3,287.5)	$ (922.9)	(4,210.4)	0.0	0.0
Total other operating items			$ (4,210.4)	$ 0.7	$ (3.2)

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Impairment of long-lived assets (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Impairment of long-lived assets	$ 3,287.5	$ 922.9	$ 4,210.4	$ 0.0	$ 0.0

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Interest expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Income and Expenses [Abstract]
Interest on debt facilities		$ 189.2	$ 246.3	$ 245.3
Loan fee amortization		44.2	12.3	12.7
Other		1.9	3.9	5.7
Total interest expense	[1]	$ 235.3	$ 262.5	$ 263.7

[1] Includes transactions with related parties. Refer to Note 19 - "Related party transactions".

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Restricted cash (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Cash and Cash Equivalents [Abstract]
Restricted cash	$ 16.4	$ 0.0

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Other assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Other Assets [Abstract]
Intangible asset - Favorable contracts	$ 0.0	$ 40.4
Mobilization revenue receivables	0.0	22.3
Prepaid expenses	26.7	14.1
Income taxes receivable	13.0	19.3
VAT receivable	5.7	10.6
Deferred mobilization costs	3.0	7.5
Reimbursable amounts due from customers	1.5	3.5
Other	3.1	1.8
Total other assets	53.0	119.5
Other current assets	45.0	119.5
Other non-current assets (1)	$ 8.0	$ 0.0

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Other assets (Narrative) (Details) - Intangible assets- Favorable contracts	12 Months Ended
	Dec. 31, 2020
Minimum
Finite-Lived Intangible Assets [Line Items]
Useful life	2 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Useful life	5 years

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Other assets (Favorable contracts) (Details) - Intangible assets- Favorable contracts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Intangible assets- Favorable contracts
Balance at beginning of period	$ 357.3	$ 357.3	$ 357.3	$ 357.3	$ 357.3
Accumulated amortization			(357.3)	(316.9)	(271.8)
Net carrying amount			$ 0.0	$ 40.4	$ 85.5
Amortization of favorable contracts	(40.4)	(45.1)
Balance at end of period	$ 357.3	$ 357.3

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Drilling units (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cost
Impairment	$ (3,287.5)	$ (922.9)	$ (4,210.4)	$ 0.0	$ 0.0
Drilling rigs
Cost
Opening balance		6,825.1	6,825.1	6,714.0
Additions			28.7	111.1
Impairment			(4,210.4)
Closing balance	2,643.4		2,643.4	6,825.1	6,714.0
Accumulated depreciation
Opening balance		$ (1,984.3)	(1,984.3)	(1,708.4)
Depreciation			(230.8)	(275.9)	(280.3)
Closing balance	(2,215.1)		(2,215.1)	(1,984.3)	(1,708.4)
Net Book Value	$ 428.3		428.3	4,840.8	5,005.6
Depreciation			$ 230.8	$ 275.9	$ 280.3

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Debt (Debt amounts outstanding) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Total principal outstanding		$ 2,892.1
Less: Debt balance held as subject to compromise	$ (2,727.1)	0.0
Debt balance not subject to compromise	0.0	2,892.1
Write-off of unamortized debt issuance costs	42.9
Line of Credit
Debt Instrument [Line Items]
Total principal outstanding	2,727.1	2,892.1
Line of Credit | Term Loan B
Debt Instrument [Line Items]
Total principal outstanding	2,727.1	2,607.6
Line of Credit | West Vela Facility
Debt Instrument [Line Items]
Total principal outstanding	0.0	151.0
Line of Credit | West Polaris Facility
Debt Instrument [Line Items]
Total principal outstanding	0.0	114.9
Line of Credit | Tender Rig Facility
Debt Instrument [Line Items]
Total principal outstanding	$ 0.0	$ 18.6

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Debt (Term Loan B) (Details) - USD ($)	1 Months Ended		4 Months Ended	12 Months Ended
	Oct. 31, 2020	Jul. 31, 2020	Oct. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jun. 26, 2014	Feb. 21, 2014
Debt Instrument [Line Items]
Interest paid			$ 8,000,000	$ 68,900,000	$ 247,600,000	$ 261,300,000
Additional default interest percent				2.00%
Drilling rigs
Debt Instrument [Line Items]
Net book value				$ 428,300,000	$ 4,840,800,000	$ 5,005,600,000
Drilling rigs | Asset Pledged as Collateral
Debt Instrument [Line Items]
Net book value				$ 428,300,000
Term Loan B | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, variable rate floor (as percent)				1.00%
Term Loan B | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity								$ 100,000,000
Term Loan B | Term Loans
Debt Instrument [Line Items]
Maximum borrowing capacity								$ 1,800,000,000
Amount outstanding				$ 2,727,100,000
Term Loan B | Term Loans | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, annual amortization payment, percent				1.00%
Basis spread (as percent)				6.00%
Additional Term Loans | Term Loans
Debt Instrument [Line Items]
Maximum borrowing capacity							$ 1,100,000,000
Debt instrument, annual amortization payment				$ 29,000,000
Super Senior Loan | Line of Credit
Debt Instrument [Line Items]
Debt face amount	$ 63,300,000	$ 63,700,000	$ 63,300,000
Commitment fee	$ 20,000,000	$ 20,000,000
Exit fee percentage	10.00%	10.00%
Super Senior Loan | Line of Credit | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread (as percent)				10.00%

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Debt (West Vela facility) (Details) - USD ($)	1 Months Ended			12 Months Ended
	Aug. 31, 2018	Feb. 28, 2018	Aug. 31, 2017	Dec. 31, 2020	Oct. 31, 2020	Apr. 30, 2020	Mar. 31, 2020	Nov. 30, 2014
Debt Instrument [Line Items]
Balloon payment						$ 15,900,000	$ 2,700,000
Revolving Credit Facility | West Vela Facility
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 1,450,000,000
Amount outstanding								$ 443,000,000
Debt instrument, annual amortization payment				$ 40,300,000
Debt prepayment cost	$ 11,900,000	$ 11,800,000	$ 46,700,000
Balloon payment					$ 120,800,000
Revolving Credit Facility | West Vela Facility | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread (as percent)				3.35%
Revolving Credit Facility | West Vela Facility | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread (as percent)				4.00%

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Debt (West Polaris facility) (Details) - USD ($)	1 Months Ended			12 Months Ended
	Aug. 31, 2018	Feb. 28, 2018	Aug. 31, 2017	Dec. 31, 2020	Jul. 31, 2020	Apr. 30, 2020	Mar. 31, 2020	Jun. 30, 2016
Debt Instrument [Line Items]
Balloon payment						$ 15,900,000	$ 2,700,000
West Polaris Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity								$ 100,000,000
Amount outstanding								$ 226,000,000
Debt instrument, annual amortization payment				$ 36,000,000
Debt prepayment cost	$ 9,400,000	$ 9,400,000	$ 37,400,000
Balloon payment					$ 93,800,000
West Polaris Facility | Revolving Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread (as percent)				3.25%
Commitment fee percentage				1.30%

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Debt (Tender rig facility) (Details) - USD ($)	1 Months Ended						12 Months Ended
	Nov. 30, 2019	Aug. 31, 2018	Feb. 28, 2018	Aug. 31, 2017	Oct. 31, 2013	May 31, 2013	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Apr. 30, 2020	Mar. 31, 2020
Debt Instrument [Line Items]
Repayments of long term debt							$ 306,600,000	$ 192,600,000	$ 296,400,000
Balloon payment										$ 15,900,000	$ 2,700,000
T-15 | Seadrill Limited
Debt Instrument [Line Items]
Proceeds from debt						$ 100,500,000
T-16 | Seadrill Limited
Debt Instrument [Line Items]
Proceeds from debt					$ 93,100,000
Secured Debt | Tender Rig Facility
Debt Instrument [Line Items]
Debt face amount							440,000,000
Debt instrument, annual amortization payment							$ 19,800,000
Debt prepayment cost		$ 3,700,000	$ 3,800,000	$ 15,800,000
Repayments of long term debt	$ 20,000,000.0
Secured Debt | Tender Rig Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread (as percent)							4.25%

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Debt (Balance sheet presentation) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt held as subject to compromise	$ 2,727.1	$ 0.0
Principal outstanding, debt due within twelve months		313.3
Debt issuance costs, debt due within twelve months		(11.9)
Debt due within twelve months	0.0	301.4
Principal outstanding, long-term external debt		2,578.8
Debt issuance costs, long-term external debt		(2.0)
Long-term debt	$ 0.0	2,576.8
Total principal outstanding		2,892.1
Total debt issuance costs		(13.9)
Total debt		$ 2,878.2

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Other liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Uncertain tax position	$ 44.4	$ 44.2
Accrued expenses	13.1	34.0
Taxes payable	31.8	35.1
Interest rate swap agreements (1)	0.0	17.7
Employee and business withheld taxes, social security and vacation payment	8.3	9.0
VAT payable	2.2	4.7
Deferred mobilization/demobilization revenues (see Note 6 - "Revenue from contracts with customers")	0.9	3.0
Total other liabilities	100.7	147.7
Other current liabilities	56.3	103.5
Other non-current liabilities	$ 44.4	$ 44.2

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Non-controlling interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Noncontrolling Interest [Abstract]
Beginning balance	$ 1,288.7	$ 1,384.5
Share of net loss allocated to the non-controlling interest	(2,038.0)	(94.3)	$ 17.9
Cash distributions		(1.5)
Ending balance	$ (749.3)	$ 1,288.7	$ 1,384.5
Seadrill Operating LLP
Noncontrolling Interest [Line Items]
Noncontrolling interest	42.00%
Seadrill Capricorn LLC
Noncontrolling Interest [Line Items]
Noncontrolling interest	49.00%
Seadrill Capricorn Holdings LLC
Noncontrolling Interest [Line Items]
Noncontrolling interest	51.00%
West Capricorn, West Sirius, West Auriga, and West Vela | Seadrill Capricorn Holdings LLC
Noncontrolling Interest [Line Items]
Noncontrolling interest	100.00%
Seadrill Operating LP
Noncontrolling Interest [Line Items]
Noncontrolling interest	58.00%
Seadrill Operating GP LLC
Noncontrolling Interest [Line Items]
Noncontrolling interest	100.00%
Seadrill Deepwater Drillship | Seadrill Operating LP
Noncontrolling Interest [Line Items]
Noncontrolling interest	56.00%
Seadrill Mobile Units | Seadrill Operating LP
Noncontrolling Interest [Line Items]
Noncontrolling interest	51.00%
West Aquarius, West Leo, West Polaris and the West Vencedor | Seadrill Operating LP
Noncontrolling Interest [Line Items]
Noncontrolling interest	100.00%

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Related party transactions (Net expenses (income) (Details) - Seadrill - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Total related party operating revenues	$ 1.1	$ 1.8	$ 4.6
Total related party operating expenses	61.5	71.6	72.1
Interest expense recognized on deferred contingent consideration	(2.0)	(3.3)	(3.1)
Related party interest expense	0.0	0.0	(1.4)
Total related party financial items	(2.0)	(3.3)	(4.5)
Related party inventory sales
Related Party Transaction [Line Items]
Total related party operating revenues	1.1	1.8	3.2
Rig operating costs
Related Party Transaction [Line Items]
Total related party operating revenues	0.0	0.0	1.4
Total related party operating expenses	0.0	0.0	0.8
Management and technical support fees
Related Party Transaction [Line Items]
Total related party operating expenses	60.1	70.5	70.6
Related party inventory purchases
Related Party Transaction [Line Items]
Total related party operating expenses	$ 1.4	$ 1.1	$ 0.7

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Related party transactions (Receivables (Payables) from Related Parties) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Less: Related party payables held as subject to compromise	$ (74.3)
Seadrill
Related Party Transaction [Line Items]
Total related party receivables	7.6	$ 6.9
Total related party payables	81.7	111.0
Less: Related party payables held as subject to compromise	(74.3)	0.0
Related party payables not subject to compromise	7.4	111.0
Seadrill | Trading balances due from Seadrill and subsidiaries
Related Party Transaction [Line Items]
Total related party receivables	7.6	6.9
Seadrill | Trading balances due to Seadrill and subsidiaries
Related Party Transaction [Line Items]
Total related party payables	78.9	79.5
Seadrill | Deferred and contingent consideration to related party - short term portion
Related Party Transaction [Line Items]
Total related party payables	$ 2.8	$ 31.5

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Related party transactions (Narrative) (Details) - USD ($) $ in Thousands		12 Months Ended
	Jul. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Management fee percentage	5.00%	5.00%
Revaluation of contingent consideration		$ 0	$ 700	$ 0
Seadrill
Related Party Transaction [Line Items]
Management fee percentage				5.00%
Seadrill | Performance guarantee
Related Party Transaction [Line Items]
Guarantee		0	15,000
Seadrill | West Vela
Related Party Transaction [Line Items]
Contract revenue cost per day, tranche one		42
Contract revenue cost per day, tranche two		$ 40
Seadrill | West Polaris
Related Party Transaction [Line Items]
Percentage of contract revenue cost per day payable, tranche one		100.00%
Percentage of contract revenue cost per day payable, tranche two		50.00%
Revaluation of contingent consideration			$ 700
Net contract dayrate, threshold		$ 450
Seadrill | Minimum
Related Party Transaction [Line Items]
Mark-up charged on costs to related parties, percent		4.85%
Seadrill | Maximum
Related Party Transaction [Line Items]
Mark-up charged on costs to related parties, percent		8.00%
Cash distribution | Seadrill
Related Party Transaction [Line Items]
Distributions				$ 6,200

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Related party transactions (Deferred and Contingent Consideration) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Current deferred and contingent consideration to related party	$ 0.0	$ 31.5
Liabilities subject to compromise	2.8	0.0
Related party transaction, deferred and contingent consideration	2.8	31.5
West Vela
Related Party Transaction [Line Items]
Fair value of liabilities	2.8	31.5
West Vela | Mobilization due to Seadrill
Related Party Transaction [Line Items]
Fair value of liabilities	2.8	17.2
West Vela | Seadrill share of dayrate from BP contract
Related Party Transaction [Line Items]
Fair value of liabilities	$ 0.0	$ 14.3

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Risk management and financial instruments (Narrative) (Details) - USD ($) $ in Millions			12 Months Ended
		Dec. 01, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative instruments, liabilities subject to compromise			$ 20.8
Derivative liability			0.0	$ 17.7
Reversal of credit risk on derivatives		$ 7.1	7.1	0.0	$ 0.0
(Loss)/gain on derivative financial instruments	[1]		$ (16.1)	(27.7)	$ 24.9
Long-term debt, percentage bearing variable interest				156.3
Revenue Benchmark | Customer Concentration Risk | One customer
Derivative [Line Items]
Concentration risk, percentage			10.00%
Interest Rate Swap
Derivative [Line Items]
Outstanding principal			$ 2,714.1	$ 2,735.8
Derivative, average fixed interest rate (as percent)			2.49%

[1] Includes transactions with related parties. Refer to Note 19 - "Related party transactions".

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Risk management and financial instruments (Interest rate swap agreements) (Details) - Interest Rate Swap - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Outstanding principal	$ 2,714.1	$ 2,735.8
Minimum
Derivative [Line Items]
Derivative, pay rate	2.45%
Maximum
Derivative [Line Items]
Derivative, pay rate	2.52%
London Interbank Offered Rate (LIBOR)
Derivative [Line Items]
Derivative, floor rate	1.00%

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Fair Value Measurement (Carrying value and estimated fair value) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value
Assets
Cash and cash equivalents	$ 362.0	$ 560.0
Restricted cash	16.4	0.0
Carrying Value
Assets
Cash and cash equivalents	362.0	560.0
Restricted cash	16.4	0.0
Term Loans | Fair Value
Liabilities
Debt	380.3	1,300.5
Term Loans | Carrying Value
Liabilities
Debt	2,727.1	2,595.9
Secured Debt | Fair Value
Liabilities
Debt	0.0	269.7
Secured Debt | Carrying Value
Liabilities
Debt	$ 0.0	$ 282.3

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Fair Value Measurement (Narrative) (Details)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability	$ 0	$ 17,700,000
Recurring
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability	20,800,000	17,700,000
Related party deferred and contingent consideration	2,800,000	31,500,000
Revolving Credit Facility | West Vela Facility
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum borrowing capacity	1,450,000,000
Secured Debt | Carrying Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt	0	282,300,000
Secured Debt | Tender Rig Facility
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt face amount	440,000,000
Term Loans | Carrying Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt	$ 2,727,100,000	$ 2,595,900,000
Discount rate | Credit facilities and long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cost of debt		0.1116

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Fair Value Measurement (Fair Value, Non-Recurring) (Details) - Fair Value, Nonrecurring $ in Millions	Dec. 31, 2020 USD ($)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Drilling units	$ 428.3
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Drilling units	$ 428.3

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Commitments and contingencies (Details) $ in Millions			1 Months Ended	12 Months Ended
	Jul. 03, 2018 USD ($)	Dec. 01, 2016	Jan. 31, 2015 drilling_unit	Dec. 31, 2019 USD ($)	Dec. 31, 2020 USD ($) contract
Loss Contingencies [Line Items]
Number of drilling rigs allegedly infringed on patents | drilling_unit			2
Long-term contracts value				$ 4,400.0
Damages sought				51 million
Number of US drilling contracts not subject to BEAT | contract					3
Guarantees					$ 11.9
West Leo
Loss Contingencies [Line Items]
Period for force majeure		60 days
Litigation recovery	$ 250.5

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Earnings per unit and cash distributions (Details) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
	Jul. 02, 2019	Dec. 31, 2020 USD ($) reporting_period $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares
Calculations of basic and diluted earnings per unit [Abstract]
Net (loss)/income attributable to Seadrill Partners LLC owners | $		$ (2,550.9)	$ (92.9)	$ 56.1
Cash distributions declared and paid in the period per unit (in USD per share)		$ 0	$ 0.22	$ 4.00
Subsequent event: Cash distributions declared and paid relating to the period per unit (in USD per share)		0	$ 0	$ 0.01
Reverse stock split ratio	0.10
Quarterly distribution of operating surplus (in USD per share)		$ 3.8750
Number of consecutive four-quarter periods distributions of available cash from operating surplus equaled or exceeded minimum quarterly distribution | reporting_period		3
First target distribution
Calculations of basic and diluted earnings per unit [Abstract]
Percentage of unit holders receiving additional distribution (as percent)		100.00%
Additional quarterly distribution per unit (in USD per share)		$ 4.456
Second target distribution
Calculations of basic and diluted earnings per unit [Abstract]
Quarterly distribution of operating surplus (in USD per share)		$ 4.844
Percentage of unit holders receiving additional distribution (as percent)		85.00%
Percentage of unit holders receiving incentive distribution (as percent)		15.00%
Third Target Distribution
Calculations of basic and diluted earnings per unit [Abstract]
Quarterly distribution of operating surplus (in USD per share)		$ 5.813
Percentage of unit holders receiving additional distribution (as percent)		75.00%
Percentage of unit holders receiving incentive distribution (as percent)		25.00%
Target Distributions Thereafter
Calculations of basic and diluted earnings per unit [Abstract]
Percentage of unit holders receiving additional distribution (as percent)		50.00%
Percentage of unit holders receiving incentive distribution (as percent)		50.00%
Common unitholders
Calculations of basic and diluted earnings per unit [Abstract]
Net (loss)/income attributable to Seadrill Partners LLC owners | $		$ (2,091.3)	$ (76.2)	$ 56.1
Weighted average units outstanding (in shares) | shares		7,528	7,528	7,528
(Loss)/Earnings per unit (in USD per share)		$ (277.80)	$ (10.12)	$ 7.45
Subordinated unitholders
Calculations of basic and diluted earnings per unit [Abstract]
Net (loss)/income attributable to Seadrill Partners LLC owners | $		$ (459.6)	$ (16.7)	$ 0.0
Weighted average units outstanding (in shares) | shares		1,654	1,654	1,654
(Loss)/Earnings per unit (in USD per share)		$ (277.80)	$ (10.12)	$ 0

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Supplementary cash flow information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Non-cash financing activities
Recognition of Super senior loan and related fees	$ 141.5	$ 0.0	$ 0.0
Reclassification of prepaid advisory fees	19.8	$ 0.0	$ 0.0
Unpaid interest converted to debt	87.0
Commitment fee converted to debt	40.0
Exit fee converted to debt	13.3
Compounded interest converted to debt	$ 1.2

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Subsequent events (Details)	Feb. 03, 2021
Subsequent Event
Subsequent Event [Line Items]
Management agreement, transition period of services	90 days