DIAMOND OFFSHORE DRILLING, INC. - Annual Report: 2017 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR

 

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

 

Delaware		76-0321760
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

15415 Katy Freeway

Houston, Texas 77094

(Address and zip code of principal executive offices)

(281) 492-5300

(Registrant’s telephone number, including area code)

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

 

Title of each class		Name of each exchange on which registered
Common Stock, $0.01 par value per share		New York Stock Exchange

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

None

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

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

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

Indicate by check mark whether the registrant has submitted electronically 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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter.

As of June 30, 2017                                                                         $694,258,330

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

As of February 9, 2018    Common Stock, $0.01 par value per share                         137,227,782 shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2018 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2017, are incorporated by reference in Part III of this report.

DIAMOND OFFSHORE DRILLING, INC.

FORM 10-K for the Year Ended December 31, 2017

TABLE OF CONTENTS

 

				Page No.
Cover Page
Document Table of Contents
Part I
Item 1.		Business			2
Item 1A.		Risk Factors			7
Item 1B.		Unresolved Staff Comments			19
Item 2.		Properties			19
Item 3.		Legal Proceedings			19
Item 4.		Mine Safety Disclosures			19
Part II
Item 5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			20
Item 6.		Selected Financial Data			22
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			44
Item 8.		Financial Statements and Supplementary Data			46
		Consolidated Financial Statements			48
		Notes to Consolidated Financial Statements			53
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			88
Item 9A.		Controls and Procedures			88
Item 9B.		Other Information			89
Part III
Item 10.		Directors, Executive Officers and Corporate Governance			89
Item 11.		Executive Compensation			89
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			89
Item 13.		Certain Relationships and Related Transactions, and Director Independence			90
Item 14.		Principal Accounting Fees and Services			90
Part IV
Item 15.		Exhibits and Financial Statement Schedules			90
Item 16.		Form 10-K Summary			93
Signatures					94

 

1

PART I

Item 1.  Business.

General

Diamond Offshore Drilling, Inc. provides contract drilling services to the energy industry around the globe with a fleet of 17 offshore drilling rigs, consisting of four drillships and seven ultra-deepwater, four deepwater and two mid-water semisubmersible rigs. The semisubmersible Ocean Victory was sold in January 2018 and the jack-up Ocean Scepter is currently being marketed for sale. Both rigs have been excluded from our current fleet total. See “— Our Fleet — Fleet Enhancements and Additions” and “— Our Fleet — Fleet Status.”

Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. Diamond Offshore Drilling, Inc. was incorporated in Delaware in 1989.

Our Fleet

Our fleet enables us to offer services in the floater market on a worldwide basis. A floater rig is a type of mobile offshore drilling rig that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs.

Semisubmersible rigs are comprised of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic positioning, or DP, to keep the rig on location, or with anchors tethered to the sea bed. Although DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats. Non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between locations.

A drillship is an adaptation of a maritime vessel that is designed and constructed to carry out drilling operations by means of a substructure with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drillsite through the use of a DP system similar to those used on semisubmersible rigs.

Our floater fleet (semisubmersibles and drillships) can be further categorized based on the nominal water depth for each class of rig as follows:

 

Category		Rated Water Depth (a) (in feet)		Number of Units in Our Fleet
Ultra-Deepwater		7,501 to 12,000		11
Deepwater		5,000 to 7,500		4
Mid-Water		400 to 4,999		2

 

(a)

Rated water depth for semisubmersibles and drillships reflects the maximum water depth in which a floating rig has been designed to operate. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on various conditions (such as salinity of the ocean, weather and sea conditions).

 

2

Fleet Status

The following table presents additional information regarding our floater fleet at January 29, 2018:

 

Rig Type and Name

Rated Water Depth (in feet)

Attributes

Year Built/ Redelivered (a)

Current Location (b)

Customer (c)

ULTRA-DEEPWATER:

Drillships (4):

Ocean BlackLion

12,000

DP; 7R; 15K

2015

GOM

Hess Corporation

Ocean BlackRhino

12,000

DP; 7R; 15K

2014

GOM

Hess Corporation

Ocean BlackHornet

12,000

DP; 7R; 15K

2014

GOM

Anadarko

Ocean BlackHawk

12,000

DP; 7R; 15K

2014

GOM

Anadarko

Semisubmersibles (7):

Ocean GreatWhite

10,000

DP; 6R; 15K

2016

Malaysia

BP

Ocean Valor

10,000

DP; 6R; 15K

2009

Brazil

Petrobras

Ocean Courage

10,000

DP; 6R; 15K

2009

Brazil

Petrobras

Ocean Confidence

10,000

DP; 6R; 15K

2001/2015

Canary Islands

Cold Stacked

Ocean Monarch

10,000

15K

2008

Australia

Warm Stacked/Cooper Energy

Ocean Endeavor

10,000

15K

2007

Italy

Cold Stacked

Ocean Rover

8,000

15K

2003

Malaysia

Cold Stacked

DEEPWATER:

Semisubmersibles (4):

Ocean Apex

6,000

15K

2014

Australia

Woodside Energy

Ocean Onyx

6,000

15K

2013

Malaysia

Cold Stacked

Ocean America

5,500

15K

1988

Malaysia

Cold Stacked

Ocean Valiant

5,500

15K

1988

North Sea/U.K.

Maersk

MID-WATER:

Semisubmersibles (2):

Ocean Patriot

3,000

15K

1983

North Sea/U.K.

Shipyard/Shell

Ocean Guardian

1,500

15K

1985

North Sea/U.K.

Warm Stacked/Decipher Prod Ltd

Attributes

 

DP    =    Dynamically Positioned/Self-Propelled		7R    =    2 Seven ram blow out preventers
6R     =    Six ram blow out preventer		15K    =    15,000 psi well control system

 

(a)	Represents year rig was built and originally placed in service or year rig was redelivered with significant enhancements that enabled the rig to be classified within a different floater category than originally constructed.

(b)	GOM means U.S. Gulf of Mexico.

(c)	For ease of presentation in this table, customer names have been shortened or abbreviated.

Fleet Enhancements and Additions. Our long-term strategy is to upgrade our fleet to meet customer demand for advanced, efficient and high-tech rigs by acquiring or building new rigs when possible to do so at attractive prices. Our most recent fleet enhancement cycle was completed in 2016, with the delivery of the Ocean GreatWhite.

We continue to evaluate further rig acquisition and enhancement opportunities as they arise. However, we can provide no assurance whether, or to what extent, we will continue to make rig acquisitions or enhancements to our fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Sources and Uses of Cash — Capital Expenditures” in Item 7 of this report.

Pressure Control by the Hour^®. In 2016, we launched an initiative to increase the operational efficiency of our rigs by reducing subsea non-productive time, or downtime incurred by a contracted rig due to the performance of routine

 

3

maintenance on or failure of subsea equipment, primarily the blowout preventer, or BOP. As part of this initiative, we entered into a ten-year collaborative arrangement with a subsidiary of GE Oil & Gas, or GE, to monitor the BOP equipment and proactively manage the maintenance, certification and reliability of such equipment. In connection with the services agreement with GE, we sold the BOP equipment to a GE affiliate and have leased back such equipment under four separate ten-year operating leases. Collectively, we refer to the services agreement with GE and the lease agreements with the GE affiliate as the “PCbtH program.” At the end of 2016, all of our drillships were participants in the PCbtH program. Since the fourth quarter of 2016 through the fourth quarter of 2017, the operational efficiency of our drillships has increased from 95.1% to 99.7%.

Markets

The principal markets for our offshore contract drilling services are:

 

•

the Gulf of Mexico, including the United States, or U.S., and Mexico;

 

•

South America, principally offshore Brazil, and Trinidad and Tobago;

 

•

Australia and Southeast Asia, including Malaysia, Indonesia and Vietnam;

 

•

Europe, principally offshore the United Kingdom, or U.K., and Norway;

 

•

East and West Africa;

 

•

the Mediterranean; and

 

•

the Middle East.

We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world. See Note 17 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.

Offshore Contract Drilling Services

Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through a competitive bid process, although it is not unusual for us to be awarded drilling contracts following direct negotiations. Our drilling contracts generally provide for a basic dayrate regardless of whether or not drilling results in a productive well. Drilling contracts generally also provide for reductions in rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate contracts may also provide for the ability to earn an incentive bonus from our customer based upon performance.

The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, in what we refer to as a well-to-well contract, or a fixed period of time, in what we refer to as a term contract. Many drilling contracts may be terminated by the customer in the event the drilling unit is destroyed or lost, or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to events beyond the control of either party to the contract. Certain of our contracts also permit the customer to terminate the contract early by giving notice; in most circumstances this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. In periods of decreasing demand for offshore rigs, drilling contractors may prefer longer term

 

4

contracts to preserve dayrates at existing levels and ensure utilization, while customers may prefer shorter contracts that allow them to more quickly obtain the benefit of declining dayrates. Moreover, drilling contractors may accept lower dayrates in a declining market in order to obtain longer-term contracts and add backlog. See “Risk Factors — We may not be able to renew or replace expiring contracts for our rigs” and “Risk Factors — Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us,” in Item 1A of this report, which are incorporated herein by reference. For a discussion of our contract backlog, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview — Contract Drilling Backlog” in Item 7 of this report, which is incorporated herein by reference.

Customers

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2017, 2016 and 2015, we performed services for 14, 18 and 19 different customers, respectively. During 2017, 2016 and 2015, our most significant customers were as follows:

 

		Percentage of Annual Consolidated Revenues
Customer		2017				2016				2015
Anadarko			24.9	%			22.4	%			12.4	%
Petróleo Brasileiro S.A.			18.9	%			17.9	%			24.1	%
Hess Corporation			16.0	%			7.7	%			0.3	%
BP			15.8	%			9.0	%			0.1	%
ExxonMobil			—				5.8	%			12.4	%

No other customer accounted for 10% or more of our annual total consolidated revenues during 2017, 2016 or 2015. See “Risk Factors — Our industry is highly competitive, with oversupply and intense price competition” and “Risk Factors — Our customer base is concentrated” in Item 1A of this report, which are incorporated herein by reference.

As of January 1, 2018, our contract backlog was $2.4 billion attributable to 13 customers. All four of our drillships are currently contracted to work in the GOM. As of January 1, 2018, contract backlog attributable to our expected operations in the GOM was $653.0 million, $554.0 million and $86.0 million for the years 2018, 2019 and 2020, respectively, all of which was attributable to two customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview — Contract Drilling Backlog” in Item 7 of this report. See “Risk Factors — We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report, which is incorporated herein by reference.

Competition

Based on industry data, as of the date of this report, there are approximately 800 mobile drilling rigs in service worldwide, including approximately 260 floater rigs. Despite consolidation in previous years, the offshore contract drilling industry remains highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do.

Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. We believe we compete favorably with respect to these factors.

We compete on a worldwide basis, but competition may vary significantly by region at any particular time. See “— Markets.” Competition for offshore rigs generally takes place on a global basis, as these rigs are highly mobile and may be moved, although at a cost that may be substantial, from one region to another. It is characteristic of the offshore

 

5

drilling industry to move rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. The current oversupply of offshore drilling rigs also intensifies price competition. See “Risk Factors — Our industry is highly competitive, with oversupply and intense price competition” in Item 1A of this report, which is incorporated herein by reference.

Governmental Regulation

Our operations are subject to numerous international, foreign, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use. See “Risk Factors — We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs” in Item 1A of this report, which are incorporated herein by reference.

Operations Outside the United States

Our operations outside the U.S. accounted for approximately 58%, 66% and 79% of our total consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. See “Risk Factors — Significant portions of our operations are conducted outside the United States and involve additional risks not associated with United States domestic operations” and “Risk Factors — We may be required to accrue additional tax liability on certain of our foreign earnings” in Item 1A of this report, which are incorporated herein by reference.

Employees

As of December 31, 2017, we had approximately 2,400 workers, including international crew personnel furnished through independent labor contractors.

Executive Officers of the Registrant

We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors and serve at the discretion of our Board of Directors until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below.

 

Marc Edwards has served as our President and Chief Executive Officer and as a Director since March 2014. Mr. Edwards previously served as a member of the Executive Committee and as Senior Vice President of the Completion and Production Division at Halliburton Company, a global diversified oilfield services company, from January 2010 to February 2014.

David L. Roland has served as our Senior Vice President, General Counsel and Secretary since September 2014. From April 2004 until joining us in 2014, Mr. Roland served as Senior Vice President, General Counsel and Corporate Secretary of ION Geophysical Corporation, a NYSE-listed geophysical company.

 

6

Thomas Roth has served as our Senior Vice President — Worldwide Operations since December 2016. Mr. Roth previously served as Vice President of the Boots & Coots Product Service Line at Halliburton Company from July 2013 to September 2015. Mr. Roth also served as Boots & Coots Global Operations Manager at Halliburton Company from August 2011 to July 2013.

Ronald Woll has served as our Senior Vice President and Chief Commercial Officer since June 2014. Mr. Woll previously served as Senior Vice President — Supply Chain at Halliburton Company from January 2011 through June 2014.

Scott Kornblau has served as our Vice President, Acting Chief Financial Officer and Treasurer since December 2017. Mr. Kornblau previously served as our Vice President and Treasurer since January 2017 and Treasurer since July 2007.

Beth G. Gordon has served as our Vice President and Controller since January 2017 and previously served as our Controller since April 2000.

Access to Company Filings

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The preceding Internet addresses and all other Internet addresses referenced in this report are for information purposes only and are not intended to be a hyperlink. Accordingly, no information found or provided at such Internet addresses or at our website in general (or at other websites linked to our website) is intended or deemed to be incorporated by reference in this report.

Item 1A.   Risk Factors.

Our business is subject to a variety of risks and uncertainties. If any of these risks or uncertainties actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected. You should carefully consider these risks when evaluating us and our securities. The following is a description of the most significant risks and uncertainties facing us; however, these risks and uncertainties are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that, as of the date of this report, we believe are not as significant as the risks described below.

The worldwide demand for drilling services has historically been dependent on the price of oil and has declined significantly as a result of the decline in oil prices, and demand has continued to be depressed in 2017.

Demand for our drilling services depends in large part upon the oil and natural gas industry’s offshore exploration and production activity and expenditure levels, which are directly affected by oil and gas prices and market expectations of potential changes in oil and gas prices. Commencing in the second half of 2014, oil prices declined significantly, resulting in a sharp decline in the demand for offshore drilling services, including services that we provide, and adversely affecting our results of operations and cash flows in 2015, 2016 and 2017, compared to previous years. Any prolonged continuation of low oil prices would have a material adverse effect on many of our customers and, therefore, on demand for our services and on our financial condition, results of operations and cash flows.

 

7

Oil prices have been, and are expected to continue to be, volatile and are affected by numerous factors beyond our control, including:

 

•

worldwide supply and demand for oil and gas;

 

•

the level of economic activity in energy-consuming markets;

 

•

the worldwide economic environment and economic trends, including recessions and the level of international trade activity;

 

•

the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels and pricing;

 

•

the level of production in non-OPEC countries;

 

•

civil unrest and the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities involving the Middle East, Russia, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;

 

•

the cost of exploring for, developing, producing and delivering oil and gas, both onshore and offshore;

 

•

the discovery rate of new oil and gas reserves;

 

•

the rate of decline of existing and new oil and gas reserves and production;

 

•

available pipeline and other oil and gas transportation and refining capacity;

 

•

the ability of oil and gas companies to raise capital;

 

•

weather conditions, including hurricanes, which can affect oil and gas operations over a wide area;

 

•

natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;

 

•

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

 

•

technological advances affecting energy consumption, including development and exploitation of alternative fuels or energy sources;

 

•

laws and regulations relating to environmental or energy security matters, including those purporting to address global climate change;

 

•

domestic and foreign tax policy; and

 

•

advances in exploration and development technology.

An increase in the price of oil and gas will not necessarily result in an increase in offshore drilling activity or an increase in the market demand for our rigs, although, historically, higher commodity prices have generally resulted in increases in offshore drilling projects. The timing of commitment to offshore activity in a cycle depends on project deployment times, reserve replacement needs, availability of capital and alternative options for resource development. Timing can also be affected by availability, access to, and cost of equipment to perform work.

Our business depends on the level of activity in the offshore oil and gas industry, which has been cyclical and is significantly affected by many factors outside of our control.

Demand for our drilling services depends upon the level of offshore oil and gas exploration, development and production in markets worldwide, and those activities depend in large part on oil and gas prices, worldwide demand for

 

8

oil and gas and a variety of political and economic factors. The level of offshore drilling activity is adversely affected when operators reduce or defer new investment in offshore projects, reduce or suspend their drilling budgets or reallocate their drilling budgets away from offshore drilling in favor of other priorities, such as shale or other land-based projects, which could reduce demand for our rigs. As a result, our business and the oil and gas industry in general are subject to cyclical fluctuations.

As a result of the cyclical fluctuations in the market, there have been periods of lower demand, excess rig supply and lower dayrates, followed by periods of higher demand, shorter rig supply and higher dayrates. We cannot predict the timing or duration of such fluctuations. Periods of lower demand or excess rig supply, which have occurred in the recent past and are continuing, intensify the competition in the industry and often result in periods of lower utilization and lower dayrates. During these periods, our rigs may not obtain contracts for future work and may be idle for long periods of time or may be able to obtain work only under contracts with lower dayrates or less favorable terms. Additionally, prolonged periods of low utilization and dayrates could also result in the recognition of further impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. See “— We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.”

Our industry is highly competitive, with oversupply and intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants. Some of our competitors may be larger companies, have larger or more technologically advanced fleets and have greater financial or other resources than we do. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.

New rig construction and upgrades of existing drilling rigs, cancelation or termination of drilling contracts and established rigs coming off contract have contributed to the current oversupply of drilling rigs, intensifying price competition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview” in Item 7 of this report.

We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized.

Generally, our customers may terminate our drilling contracts under certain circumstances, such as the destruction or loss of a drilling rig, if we suspend drilling operations for a specified period of time as a result of a breakdown of major equipment, excessive downtime for repairs, failure to meet minimum performance criteria (including customer acceptance testing) or, in some cases, due to other events beyond the control of either party.

In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods, often by tendering contractually specified termination amounts, which may not fully compensate us for the loss of the contract. During depressed market conditions, such as those currently in effect, certain customers have utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts. Additionally, because of depressed commodity prices, restricted credit markets, economic downturns, changes in priorities or strategy or other factors beyond our control, a customer may no longer want or need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. For these reasons, customers may seek to renegotiate the terms of our existing drilling contracts, terminate our contracts without justification or repudiate or otherwise fail to perform their obligations under our contracts. As a result of such contract renegotiations or terminations, our contract backlog may be adversely impacted. We might not recover any compensation (or any recovery

 

9

we obtain may not fully compensate us for the loss of the contract) and we may be required to idle one or more rigs for an extended period of time. Each of these results could have a material adverse effect on our financial condition, results of operations and cash flows. See “— Our industry is highly competitive, with oversupply and intense price competition” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview — Contract Drilling Backlog” in Item 7 of this report.

We may not be able to renew or replace expiring contracts for our rigs.

As of the date of this report, all of our current customer contracts will expire between 2018 and 2020. Our ability to renew or replace expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers, at such times. Given the historically cyclical and highly competitive nature of our industry, we may not be able to renew or replace the contracts or we may be required to renew or replace expiring contracts or obtain new contracts at dayrates that are below, and likely substantially below, existing dayrates, or that have terms that are less favorable to us than our existing contracts. Moreover, we may be unable to secure contracts for these rigs. Failure to secure contracts for a rig may result in a decision to cold stack the rig, which puts the rig at risk for impairment and may competitively disadvantage the rig as customers, during the most recent market downturn, have expressed a preference for ready or “hot” stacked rigs over cold-stacked rigs.

We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs.

The current oversupply of drilling rigs in the offshore drilling market has resulted in numerous rigs being idled and in some cases retired and/or scrapped. We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable, and we could incur additional impairment charges related to the carrying value of our drilling rigs. Impairment write-offs could result if, for example, any of our rigs become obsolete or commercially less desirable due to changes in technology, market demand or market expectations or their carrying values become excessive due to the condition of the rig, cold stacking the rig, the expectation of cold stacking the rig in the near future, contracted backlog of less than one year for a rig, a decision to retire or scrap the rig, or excess spending over budget on a new-build construction project or major rig upgrade. We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment, reflecting management’s assumptions and estimates regarding the appropriate risk-adjusted dayrate by rig, future industry conditions and operations and other factors. Asset impairment evaluations are, by their nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets, which could impact the need to record an impairment charge and the amount of any charge taken. Since 2012, we have retired and sold 27 drilling rigs and recorded impairment losses aggregating $1.7 billion, including $99.3 million recognized in 2017. Historically, the longer a drilling rig remains cold stacked, the higher the cost of reactivation and, depending on the age, technological obsolescence and condition of the rig, the lower the likelihood that the rig will be reactivated at a future date. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview — Critical Accounting Estimates — Property, Plant and Equipment” in Item 7 of this report and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

We can provide no assurance that our assumptions and estimates used in our asset impairment evaluations will ultimately be realized or that the current carrying value of our property and equipment, including rigs designated as held for sale, will ultimately be realized.

Our customer base is concentrated.

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2017, two of our customers in the GOM and our three largest customers in the aggregate accounted for 41% and 60%, respectively, of our annual total consolidated revenues. In addition, the number of customers we have performed services for has declined from 35 in 2014 to 14 in 2017. The loss of a significant

 

10

customer could have a material adverse impact on our financial condition, results of operations and cash flows, especially in a declining market where the number of our working drilling rigs is declining along with the number of our active customers. In addition, if a significant customer experiences liquidity constraints or other financial difficulties, or elects to terminate one of our drilling contracts, it could materially adversely affect our utilization rates in the affected market and also displace demand for our other drilling rigs as the resulting excess supply enters the market. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Overview — Contract Drilling Backlog” in Item 7 of this report.

We may be subject to litigation and disputes that could have a material adverse effect on us.

We are, from time to time, involved in litigation and disputes. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters, claims of infringement of patent and other intellectual property rights, and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any dispute, claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. We may not have insurance for litigation or claims that may arise, or if we do have insurance coverage it may not be sufficient, insurers may not remain solvent, other claims may exhaust some or all of the insurance available to us or insurers may interpret our insurance policies such that they do not cover losses for which we make claims or may otherwise dispute claims made. Litigation may have a material adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other risk factors inherent in litigation or relating to the claims that may arise.

Our contract drilling expense includes fixed costs that will not decline in proportion to decreases in rig utilization and dayrates.

Our contract drilling expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs will not decline and often we may incur additional operating costs, such as fuel and catering costs, for which we are generally reimbursed by the customer when a rig is under contract. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with cold stacking a rig (particularly if we cold stack a newer rig, such as a drillship or other DP semisubmersible rig, for which cold-stacking costs are typically substantially higher than for an older floater rig), or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in contract drilling expense.

Contracts for our drilling rigs are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.

Our contracts for our drilling rigs generally provide for the payment of an agreed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs we incur on the project. Many of our operating costs, such as labor costs, are unpredictable and may fluctuate based on events beyond our control. In addition, equipment repair and maintenance expenses vary depending on the type of activity the rig is performing, the age and condition of the equipment and general market factors impacting relevant parts, components and services. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers.

Changes in tax laws, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results.

Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our worldwide operations through various subsidiaries in a number of countries throughout the world. As a result, we are subject to

 

11

highly complex tax laws, regulations and income tax treaties within and between the countries in which we operate as well as countries in which we may be resident, which may change and are subject to interpretation. We determine our income tax expense based on our interpretation of the applicable tax laws and regulations in effect in each jurisdiction for the period during which we operate and earn income. Our overall effective tax rate could be adversely and suddenly affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax law, tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial.

Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any tax position taken or intercompany pricing policies, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to us or our operations, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially.

We are subject to extensive domestic and international laws and regulations that could significantly limit our business activities and revenues and increase our costs.

Certain countries are subject to restrictions, sanctions and embargoes imposed by the United States government or other governmental or international authorities. These restrictions, sanctions and embargoes may prohibit or limit us from participating in certain business activities in those countries. Our operations are also subject to numerous local, state and federal laws and regulations in the United States and in foreign jurisdictions concerning the containment and disposal of hazardous materials, the remediation of contaminated properties and the protection of the environment. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. Failure to comply with such laws and regulations could subject us to civil or criminal enforcement action, for which we may not receive contractual indemnification or have insurance coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected areas. We may be required to make significant expenditures for additional capital equipment or inspections and recertifications thereof to comply with existing or new governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or result in a reduction in revenues associated with downtime required to install such equipment or may otherwise significantly limit drilling activity.

In addition, our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. These special surveys are generally performed in a shipyard and require scheduled downtime, which can negatively impact operating revenue. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, and inspection, repair and maintenance costs. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter. Operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between special surveys. Although an intermediate survey normally does not require shipyard time, the survey may require some downtime for the rig. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects.

In addition, the offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, can be affected by changes in tax and other laws relating to the energy business generally. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or

 

12

the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could limit drilling opportunities.

U.S. federal and state, foreign and international laws and regulations address oil spill prevention and control and impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. Some of these laws and regulations have significantly expanded liability exposure across all segments of the oil and gas industry. For example, the United States Oil Pollution Act of 1990 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages. Failure to comply with such laws and regulations could subject us to civil or criminal enforcement action, for which we may not receive contractual indemnification or have insurance coverage, and could result in the issuance of injunctions restricting some or all of our activities in the affected areas. In addition, legislative and regulatory developments may occur that could substantially increase our exposure to liabilities that might arise in connection with our operations.

Governments around the world are also increasingly considering and adopting laws and regulations to address climate change issues. Lawmakers and regulators in the United States and other jurisdictions where we operate have focused increasingly on restricting the emission of carbon dioxide, methane and other “greenhouse” gases. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business, and could adversely affect our operations by limiting drilling opportunities.

If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to delay, suspend or cease our operations.

Oil and natural gas exploration and production operations require numerous permits and approvals for us and our customers from governmental agencies in the areas in which we operate or expect to operate. Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse change in the interpretation of existing permits and approvals. In addition, such regulatory requirements and restrictions could also delay or curtail our operations.

Our business involves numerous operating hazards that could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.

Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel and damage to producing or potentially productive oil and gas formations, oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to marine hazards, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of suppliers or subcontractors to perform or supply goods or services or personnel shortages. Any of the foregoing events could result in significant damage or loss to our properties and assets or the properties and assets of others, injury or death to rig personnel or others, significant loss of revenues and significant damage claims against us.

Our drilling contracts with our customers provide for varying levels of indemnity and allocation of liabilities between our customers and us with respect to the hazards and risks inherent in, and damages or losses arising out of, our

 

13

operations, and we may not be fully protected. Our contracts are individually negotiated, and the levels of indemnity and allocation of liabilities in them can vary from contract to contract depending on market conditions, particular customer requirements and other factors existing at the time a contract is negotiated. We may incur liability for significant losses or damages under such provisions.

Additionally, the enforceability of indemnification provisions in our contracts may be limited or prohibited by applicable law or such provisions may not be enforced by courts having jurisdiction, and we could be held liable for substantial losses or damages and for fines and penalties imposed by regulatory authorities. The indemnification provisions in our contracts may be subject to differing interpretations, and the laws or courts of certain jurisdictions may enforce such provisions while other laws or courts may find them to be unenforceable. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is unsettled under certain laws that are applicable to our contracts. There can be no assurance that our contracts with our customers, suppliers and subcontractors will fully protect us against all hazards and risks inherent in our operations. There can also be no assurance that those parties with contractual obligations to indemnify us will be financially able to do so or will otherwise honor their contractual obligations.

We maintain liability insurance, which generally includes coverage for environmental damage; however, because of contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim costs. In addition, certain risks and contingencies related to pollution, reservoir damage and environmental risks are generally not fully insurable. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.

We are self-insured for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of material losses that are not covered by third party insurance contracts. In addition, certain of our shore-based facilities are located in geographic regions that are susceptible to damage or disruption from hurricanes and other weather events. Future hurricanes or similar natural disasters that impact our facilities, our personnel located at those facilities or our ongoing operations may negatively affect our financial position and operating results.

If an accident or other event occurs that exceeds our insurance coverage limits or is not an insurable event under our insurance policies, or is not fully covered by contractual indemnity, it could result in a significant loss to us.

Significant portions of our operations are conducted outside the United States and involve additional risks not associated with United States domestic operations.

Our operations outside the United States accounted for approximately 58%, 66% and 79% of our total consolidated revenues for 2017, 2016 and 2015, respectively, and include, or have included, operations in South America, Australia and Southeast Asia, Europe, East and West Africa, the Mediterranean and Mexico. Because we operate in various regions throughout the world, we are exposed to a variety of risks inherent in international operations, including risks of war or conflicts; political and economic instability and disruption; civil disturbance; acts of piracy, terrorism or other assaults on property or personnel; corruption; possible economic and legal sanctions (such as possible restrictions against countries that the U.S. government may consider to be state sponsors of terrorism); changes in global monetary and trade policies, laws and regulations; fluctuations in currency exchange rates; restrictions on currency exchange; controls over the repatriation of income or capital; and other risks. We may not have insurance coverage for these risks, or we may not be able to obtain adequate insurance coverage for such events at reasonable rates. Our operations may become restricted, disrupted or prohibited in any country in which any of these risks occur.

We are also subject to the following risks in connection with our international operations:

 

•

kidnapping of personnel;

 

14

•

seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of property or equipment;

 

•

renegotiation or nullification of existing contracts;

 

•

disputes and legal proceedings in international jurisdictions;

 

•

changing social, political and economic conditions;

 

•

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

 

•

difficulties in collecting accounts receivable and longer collection periods;

 

•

fluctuations in currency exchange rates and restrictions on currency exchange;

 

•

regulatory or financial requirements to comply with foreign bureaucratic actions;

 

•

restriction or disruption of business activities;

 

•

limitation of our access to markets for periods of time;

 

•

travel limitations or operational problems caused by public health threats or changes in immigration policies;

 

•

difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;

 

•

difficulties in obtaining visas or work permits for our employees on a timely basis; and

 

•

changing taxation policies and confiscatory or discriminatory taxation.

We are also subject to the regulations of the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations in addition to domestic and international anti-bribery laws and sanctions, trade laws and regulations, customs laws and regulations, and other restrictions imposed by other governmental or international authorities. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to us, among other things. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act 2010 or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions. In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling rigs; import-export quotas or other trade barriers; repatriation of foreign earnings or capital; oil and gas exploration and development; local content requirements; taxation of offshore earnings and earnings of expatriate personnel; and use and compensation of local employees and suppliers by foreign contractors.

Our consolidated effective income tax rate may vary substantially from one reporting period to another.

Our consolidated effective income tax rate is impacted by the mix between our domestic and international pre-tax earnings or losses, as well as the mix of the international tax jurisdictions in which we operate. We cannot provide any assurances as to what our consolidated effective income tax rate will be in the future due to, among other factors, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.S. and foreign tax laws, regulations or treaties or the

 

15

interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. This variability may cause our consolidated effective income tax rate to vary substantially from one reporting period to another.

We may be required to accrue additional tax liability on certain of our foreign earnings.

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC, a Cayman Islands subsidiary that we own. It is our intention to continue to indefinitely reinvest the earnings of DFAC and its foreign subsidiaries to finance our foreign activities. We do not expect to provide for U.S. taxes on any earnings generated by DFAC and its foreign subsidiaries, except to the extent that these earnings are immediately subjected to U. S. federal income tax (such as under the Tax Cuts and Jobs Act of 2017). Should a future distribution be made from any unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes and/or withholding taxes in certain jurisdictions; however, it is not practical to estimate this potential liability.

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

Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could adversely affect the market for offshore drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

Although we have paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future, and we can give no assurance as to the amount or timing of the payment of any future dividends.

We pay dividends at the discretion of our Board of Directors, or Board. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividend Policy” in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of this report.

We rely on third-party suppliers, manufacturers and service providers to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction.

Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes us to volatility in the quality, price and availability of such items. Certain components, parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well as an increase in operating costs and an increased risk of additional asset impairments.

 

16

Additionally, our suppliers, manufacturers and service providers could be negatively impacted by current industry conditions or global economic conditions. If certain of our suppliers, manufacturers or service providers were to experience significant cash flow issues, become insolvent or otherwise curtail or discontinue their business as a result of such conditions, it could result in a reduction or interruption in supplies, equipment or services available to us and/or a significant increase in the price of such supplies, equipment and services.

We must make substantial capital and operating expenditures to build, maintain, and upgrade our drilling fleet.

Our business is highly capital intensive and dependent on having sufficient cash flow and/or available sources of financing in order to fund our desired capital expenditure requirements. Our expenditures could increase as a result of changes in offshore drilling technology; the cost of labor and materials; customer requirements; the cost of replacement parts for existing drilling rigs; and industry standards. Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations, safety or other equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. We can provide no assurance that we will have access to adequate or economical sources of capital to fund our capital expenditures.

Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.

Our business is highly capital intensive and dependent on having sufficient cash flow and/or available sources of financing in order to fund our capital expenditure requirements. As of December 31, 2017, we had outstanding approximately $2.0 billion of senior notes, maturing at various times from 2023 through 2043. As of February 9, 2018, we had no borrowings outstanding under our revolving credit facility and $1.5 billion available under our credit facility to meet our short-term liquidity requirements. We may incur additional indebtedness in the future and borrow from time to time under our revolving credit facility to fund working capital or other needs, subject to compliance with its covenants.

Our ability to meet our debt service obligations is dependent upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. High levels of indebtedness could have negative consequences to us, including:

 

•

we may have difficulty satisfying our obligations with respect to our outstanding debt;

 

•

we may have difficulty obtaining financing in the future for working capital, capital expenditures, acquisitions or other purposes;

 

•

we may need to use a substantial portion of our available cash flow from operations to pay interest and principal on our debt, which would reduce the amount of money available to fund working capital requirements, capital expenditures, the payment of dividends and other general corporate or business activities;

 

•

our vulnerability to the effects of general economic downturns, adverse industry conditions and adverse operating results could increase;

 

•

our flexibility in planning for, or reacting to, changes in our business and in our industry in general could be limited;

 

•

we may not have the ability to pursue business opportunities that become available to us;

 

•

our amount of debt and the amount we must pay to service our debt obligations could place us at a competitive disadvantage compared to our competitors that have less debt;

 

17

•

our customers may react adversely to our significant debt level and seek alternative service providers; and

 

•

our failure to comply with the restrictive covenants in our debt instruments that, among other things, require us to maintain a specified ratio of our consolidated indebtedness to total capitalization and limit the ability of our subsidiaries to incur debt, could result in an event of default that, if not cured or waived, could have a material adverse effect on our business.

In addition, our $1.5 billion revolving credit facility matures on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that mature on October 22, 2019. Our ability to renew or replace our revolving credit facility is dependent on numerous factors, including our financial condition and prospects at the time and the then current state of the bank and capital markets in the U.S. Our liquidity may be adversely affected if we are unable to replace our revolving credit facility upon acceptable terms when it matures.

In July 2017, Moody’s Investor Services downgraded our corporate credit rating to Ba3 with a negative outlook from Ba2 with a stable outlook. In October 2017, S&P Global Ratings, or S&P, downgraded our corporate credit rating to B+ from BB-; our outlook by S&P remains negative. These credit ratings are below investment grade and could raise our cost of financing. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.

Our revolving credit facility bears interest at variable rates, based on our corporate credit rating and market interest rates. If market interest rates increase, our cost to borrow under our revolving credit facility may also increase. Although we may employ hedging strategies such that a portion of the aggregate principal amount outstanding under our credit facility would effectively carry a fixed rate of interest, any hedging arrangement put in place may not offer complete protection from this risk.

Any significant cyber attack or other interruption in network security or the operation of critical computer systems could materially disrupt our operations and adversely affect our business.

Our business has become increasingly dependent upon information technologies, systems and networks to conduct day-to-day operations, and we are placing greater reliance on technology to help support our operations and increase efficiency in our business functions. We are dependent upon our information technology and infrastructure, including operational and financial computer systems, to process the data necessary to conduct almost all aspects of our business. Computer and other business facilities and systems could become unavailable or impaired from a variety of causes including, among others, storms and other natural disasters, terrorist attacks, utility outages, theft, design defects, human error or complications encountered as existing systems are maintained, repaired, replaced or upgraded. It has also been reported that known or unknown entities or groups have mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. A breach or failure of our computer systems or networks, or those of our customers, vendors or others with whom we do business, could materially disrupt our business operations and our customers’ operations and could result in the alteration, loss, theft or corruption of data or unauthorized release of confidential, proprietary or sensitive data concerning our company, business activities, employees, customers or vendors. Any such breach or failure could have a material adverse effect on our operations, business or reputation.

Failure to obtain and retain highly skilled personnel could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our business. A well-trained, motivated and adequately-staffed work force has a positive impact on our ability to attract and retain business. As a result, our future success depends on our continuing ability to identify, hire, develop, motivate and retain skilled personnel for all areas of our organization. To the extent that demand for drilling services and/or the size of the active worldwide industry fleet increases, shortages of qualified personnel could arise, creating upward pressure on wages and

 

18

difficulty in staffing and servicing our rigs. Our continued ability to compete effectively depends on our ability to attract new employees and to retain and motivate our existing employees. Heightened competition for skilled personnel could materially and adversely limit our operations and further increase our costs.

We are controlled by a single stockholder, which could result in potential conflicts of interest.

Loews Corporation, which we refer to as Loews, beneficially owned approximately 53% of our outstanding shares of common stock as of February 9, 2018, and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. We have also entered into a services agreement and a registration rights agreement with Loews, and we may in the future enter into other agreements with Loews.

Loews is a holding company, with principal subsidiaries (in addition to us) consisting of CNA Financial Corporation, a 90%-owned subsidiary engaged in commercial property and casualty insurance; Boardwalk Pipeline Partners, LP, a 51%-owned subsidiary engaged in the transportation and storage of natural gas and natural gas liquids; Loews Hotels & Co, a wholly-owned subsidiary engaged in the operation of a chain of hotels; and Consolidated Container Company, a 99% subsidiary providing packaging solutions to end markets such as beverage, food and household chemicals. It is possible that potential conflicts of interest could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations.

Item 1B.   Unresolved Staff Comments.

Not applicable.

Item 2.   Properties.

We own an office building in Houston, Texas, where our corporate headquarters are located. We also own offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil and Ciudad del Carmen, Mexico. Additionally, we currently lease various office, warehouse and storage facilities in Australia, Louisiana, Malaysia, Singapore and the U.K. to support our offshore drilling operations.

Item 3.   Legal Proceedings.

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

Item 4.   Mine Safety Disclosures.

Not applicable.

 

19

PART II

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

Price Range of Common Stock

Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common stock as reported by the NYSE.

 

		Common Stock
		High				Low
2017
First Quarter		$	19.49			$	14.70
Second Quarter			16.31				10.26
Third Quarter			14.85				10.22
Fourth Quarter			18.94				14.31
2016
First Quarter		$	24.09			$	15.55
Second Quarter			26.04				20.28
Third Quarter			26.11				14.80
Fourth Quarter			21.08				15.42

As of February 9, 2018, there were approximately 149 holders of record of our common stock. This number represents registered stockholders and does not include stockholders who hold their shares through an institution.

Dividend Policy

We pay dividends at the discretion of our Board of Directors. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Risk Factors — Although we have paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future, and we can give no assurance as to the amount or timing of the payment of any future dividends” in Item 1A of this report, which is incorporated herein by reference. We discontinued our regular cash dividend in 2016.

 

20

CUMULATIVE TOTAL STOCKHOLDER RETURN

The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 400 MidCap Index and the Dow Jones U.S. Oil Equipment & Services index over the five year period ended December 31, 2017.

Comparison of Five-Year Cumulative Total Return ⁽¹⁾

 

 

		Dec. 31, 2012				Dec. 31, 2013				Dec. 31, 2014				Dec. 31, 2015				Dec. 31, 2016				Dec. 31, 2017
Diamond Offshore			100				88				62				36				30				32
S&P 400 MidCap Index			100				133				146				143				173				201
Dow Jones U.S. Oil Equipment & Services			100				128				106				82				105				87

(1)	Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2012 in our common stock and the two published indices.

Our dividend history for the periods reported above is as follows:

 

		Q1								Q2								Q3								Q4
Year		Regular				Special				Regular				Special				Regular				Special				Regular				Special
2017		$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	—
2016		$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	—
2015		$	0.125			$	—			$	0.125			$	—			$	0.125			$	—			$	0.125			$	—
2014		$	0.125			$	0.75			$	0.125			$	0.75			$	0.125			$	0.75			$	0.125			$	0.75
2013		$	0.125			$	0.75			$	0.125			$	0.75			$	0.125			$	0.75			$	0.125			$	0.75

 

21

Item 6.   Selected Financial Data.

The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. The selected consolidated financial data below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.

 

		As of and for the Year Ended December 31,
		2017				2016				2015				2014				2013
		(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues		$	1,485,746			$	1,600,342			$	2,419,393			$	2,814,671			$	2,920,421
Operating income (loss)			123,879	(1)			(356,884	) (1)			(294,074	) (1)			572,562	(1)			801,606
Net income (loss)			18,346				(372,503	)			(274,285	)			387,011				548,686
Net income (loss) per share:
Basic			0.13				(2.72	)			(2.00	)			2.82				3.95
Diluted			0.13				(2.72	)			(2.00	)			2.81				3.95
Balance Sheet Data:
Drilling and other property and equipment, net		$	5,261,641	(1)		$	5,726,935	(1)		$	6,378,814	(1)		$	6,945,953	(1)		$	5,467,227
Total assets			6,250,570				6,371,877				7,149,894	(2)			8,005,398	(2)			8,374,437	(2)
Long-term debt (excluding current maturities) (3)			1,972,225				1,980,884				1,979,778	(2)			1,978,635	(2)			2,227,192	(2)
Other Financial Data:
Capital expenditures, excluding accruals		$	139,581			$	652,673			$	830,655			$	2,032,764	(4)		$	957,598
Cash dividends declared per share			—				—				0.50				3.50				3.50
Ratio of earnings to fixed charges (5)			0.91	x			(3.21	)x (6)			(2.45	)x (6)			4.64	x			7.79	x

 

(1)

During 2017, 2016, 2015 and 2014 we recorded impairment losses aggregating $99.3 million, $678.1 million, $860.4 million and $109.5 million, respectively, to write down certain of our drilling rigs and related equipment with indicators of impairment to their estimated recoverable amounts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Years Ended December 31, 2017, 2016, and 2015 — Overview — 2017 Compared to 2016 — Impairment of Assets” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Years Ended December 31, 2017, 2016 and 2015 — Overview — 2016 Compared to 2015 — Impairment of Assets” in Item 7 and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report for a discussion of these impairments.

(2)

Historical data for the three annual periods ending on or before December 31, 2015 has been restated to reflect the effect thereon of the adoption on January 1, 2016 of an accounting standard which requires debt issuance costs associated with our senior notes to be presented in the balance sheet as a reduction in the related long-term debt. Prior to the adoption of this accounting standard, debt issuance costs associated with our senior notes were presented as “Prepaid expenses and other current assets” and “Other assets” in our Consolidated Balance Sheets. See Note 1 “General Information — Debt Issuance Costs” to our Consolidated Financial Statements in Item 8 of this report.

(3)	See Note 9 “Credit Agreement and Senior Notes” to our Consolidated Financial Statements included in Item 8 of this report for a discussion of changes to our long-term debt.

(4)	During 2014, we took delivery of three ultra-deepwater drillships and two deepwater semisubmersible rigs. The aggregate net book value of these newly constructed rigs was $2.7 billion at December 31, 2014, of which $1.3 billion was reported in construction work-in-progress at December 31, 2013.

(5)

For all periods presented, the ratio of earnings to fixed charges has been computed on a total enterprise basis. Earnings represent pre-tax income (loss) from continuing operations plus fixed charges. Fixed charges include (i) interest, whether expensed or capitalized, (ii) amortization of debt issuance costs, whether expensed or capitalized, and (iii) a portion of rent expense, which we believe represents the interest factor attributable to rent.

(6)	The deficiency in our earnings available for fixed charges for the years ended December 31, 2016 and 2015 was $479.8 million and $388.9 million, respectively.

 

22

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

The following discussion should be read in conjunction with our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.

We provide contract drilling services to the energy industry around the globe with a fleet of 17 offshore drilling rigs, consisting of four drillships and seven ultra-deepwater, four deepwater and two mid-water semisubmersible rigs. The semisubmersible Ocean Victory was sold in January 2018 and the jack-up Ocean Scepter is currently being marketed for sale. We have excluded both rigs from our current fleet total.

Market Overview

Oil prices have partially rebounded from the historical 12-year low of less than $30 per barrel in January 2016 to the upper $60s-per-barrel range at the end of January 2018. The increase in commodity price is in part due to the late December 2017 shutdown of a major North Sea pipeline which led to production shutdowns at several offshore fields, and, production cuts by certain members of the Organization of Petroleum Exporting Countries, or OPEC, and others that went into effect in 2017 to reduce the oversupply of oil and raise and potentially stabilize oil prices. However, the increase in oil prices has not yet resulted in a measurable increase in demand for offshore contract drilling services or higher dayrates as capital spending for offshore exploration and development remains at a relatively low level at the start of 2018. As a consequence, the offshore contract drilling industry remains weak.

Industry analysts have reported that in 2017, for the third consecutive year, the global supply of floater rigs decreased with 30 floaters being scrapped during the year, for a total of over 80 floaters retired since 2015. Despite these events, the oversupply of drilling rigs in the floater markets continues to persist as drilling rigs across all water depth categories continue to be cold stacked as they come off contract with no immediate future work. Industry reports indicate that there remain approximately 40 newbuild floaters on order with scheduled deliveries between 2018 and 2021. Industry analysts predict that the 2018 delivery dates may be deferred.

Given the oversupply of rigs, competition for the limited number of offshore drilling jobs remains intense. In some cases, dayrates have been negotiated at break-even or below-cost levels in order to enable the drilling contractor to recover a portion of operating costs for rigs that would otherwise be uncontracted or cold stacked. In addition, customers have indicated a preference for “hot” rigs rather than reactivated cold-stacked rigs. This preference incentivizes the drilling contractor to contract rigs at lower rates for the sole purpose of maintaining the rigs in an active state and allowing for at least partial cost recovery.

Our results of operations and cash flows for the three years ended December 31, 2017 have been materially impacted by continuing depressed market conditions in the offshore drilling industry. We currently expect that these adverse market conditions will continue for the near term, which could result in more of our rigs being without contracts, contracted at lower rates than the rigs are currently earning and/or cold stacked or scrapped. These events, if they were to occur, could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack or elect to scrap a rig, we evaluate the rig for impairment. During 2017, 2016 and 2015, we recognized aggregate impairment losses of $99.3 million (three rigs), $678.1 million (eight rigs and related spares) and $860.4 million (17 rigs). See “— Results of Operations — Overview — 2017 Compared to 2016 — Impairment of Assets,” “— Results of Operations — Overview — 2016 Compared to 2015 — Impairment of Assets,” “Risk Factors — We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs” in Item 1A of this report and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

Historically, the longer a drilling rig remains cold stacked, the higher the cost of reactivation and, depending on the age, technological obsolescence and condition of the rig, the lower the likelihood that the rig will be reactivated at a future date. As of January 29, 2018, five rigs in our fleet were cold stacked.

See “— Contract Drilling Backlog” for future commitments of our rigs during 2018 through 2020.

 

23

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of January 1, 2018 (based on contract information known at that time), October 1, 2017 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2017), and January 1, 2017 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2016). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog. See “Risk Factors — We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report, which is incorporated herein by reference.

 

		January 1, 2018				October 1, 2017				January 1, 2017
		(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters		$	2,222,000			$	2,413,000			$	3,215,000
Deepwater Floaters			90,000				86,000				197,000
Other Rigs (1)			105,000				118,000				152,000
Total		$	2,417,000			$	2,617,000			$	3,564,000

 

(1)	Includes contract drilling backlog for our mid-water floaters and, and for periods prior to 2018, our jack-up rig.

The following table reflects the amount of our contract drilling backlog by year as of January 1, 2018.

 

		For the Years Ending December 31,
		Total				2018				2019				2020
		(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters		$	2,222,000			$	1,062,000			$	927,000			$	233,000
Deepwater Floaters			90,000				45,000				45,000				—
Other Rigs (1)			105,000				42,000				45,000				18,000
Total		$	2,417,000			$	1,149,000			$	1,017,000			$	251,000

 

(1)	Includes contract drilling backlog for our mid-water floaters.

 

24

The following table reflects the percentage of rig days committed by year as of January 1, 2018. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs multiplied by the number of days in a particular year).

 

		For the Years Ending December 31,
		2018				2019				2020
Rig Days Committed (1)
Ultra-Deepwater Floaters			71	%			59	%			17	%
Deepwater Floaters			29	%			24	%			—
Other Rigs (2)			37	%			33	%			12	%

 

(1)	As of January 1, 2018, includes approximately 95 currently known, scheduled shipyard days for contract preparation, surveys and extended maintenance projects, as well as mobilization days, for the year 2018.

(2)	Includes rig days committed for our mid-water floaters.

Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows

Operating Income. Our operating income is primarily a function of contract drilling revenue earned less contract drilling expenses incurred or recognized. The two most significant variables affecting our contract drilling revenue are the dayrates earned and utilization rates achieved by our rigs, each of which is a function of rig supply and demand in the marketplace. These factors are not entirely within our control and are difficult to predict. We generally recognize revenue from dayrate drilling contracts as services are performed. Consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result.

Revenue is also affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, we may receive fees for the mobilization of equipment. In addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which we may or may not be compensated. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation fees received (on either a lump-sum or dayrate basis), as well as direct and incremental costs associated with the mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the term of the related drilling contracts. Absent a contract, mobilization costs are recognized currently.

Operating income also fluctuates due to varying levels of contract drilling expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment, which generally are not affected by changes in dayrates and short-term reductions in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm-stacked” state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if a rig is expected to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. The cost of cold stacking a rig can vary depending on the type of rig. The cost of cold stacking a drillship, for example, is typically substantially higher than the cost of cold stacking a jack-up rig or an older floater rig.

The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs associated with training employees can be significant. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is

 

25

performing, as well as the age and condition of the equipment and the regions in which our rigs are working. See “— Contractual Cash Obligations — Pressure Control by the Hour^®.”

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs, which are recognized as incurred. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter.

During 2018, we expect to spend approximately 20 and 75 days for special surveys and upgrades for the Ocean Patriot and Ocean Valiant, respectively. Additionally, we expect to spend approximately 35 days for a special survey for the Ocean Valor in 2018, during the paid contracted standby period. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “— Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, which renewed effective May 1, 2017, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our current insurance policy, which renewed effective May 1, 2017, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage related to insurable events arising due to named windstorms in the U.S. Gulf of Mexico is $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. Our deductibles for other marine liability coverage, including personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.

2017 Reduction Plan. The contract drilling industry has experienced a severe downturn that began in mid-2014 with a dramatic decline in oil prices, resulting in a lack of demand for the services we provide, primarily in the area of deepwater drilling. This lack of demand, combined with a significant oversupply of drilling rigs, has caused our management to again review our organizational and operational structure, in an effort to further reduce our operating profile. In late 2017, we undertook a reorganization of our operational structure, including the identification of redundant positions and, among other things, negotiated the termination of our agency relationship in Brazil. For the year ended December 31, 2017, we recognized $14.1 million in “Restructuring and separation costs” in our Consolidated Statements of Operations primarily associated with the severance of certain executives and other employees and termination of our agency agreement in Brazil, the majority of which was unpaid at December 31, 2017. As we continue to position our organization to compete effectively in what we continue to expect to be a protracted downturn, we expect to continue our assessment of our organizational structure during 2018. For the first quarter of 2018, we expect to incur approximately $3 million in severance costs for additional redundant employees. If market conditions do not significantly improve in the near term and the market downturn remains protracted, additional actions may be required to further reduce our cost profile.

 

26

Impact of Changes in Tax Laws or Their Interpretation. We operate through our various subsidiaries in a number of countries throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act amended the Internal Revenue Code in several areas that had a direct and immediate effect on our results of operations and statement of financial position as of and for the year ended December 31, 2017, including, among other items, a one-time mandatory deemed repatriation of accumulated earnings of our foreign subsidiaries as of December 31, 2017 and a reduction in the U.S corporate income tax rate from 35% to 21% beginning in January 2018. We have used our best judgment to estimate the impact of the Tax Reform Act on our reported results. Due to the timing of the enactment of the Tax Reform Act, there continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pending further guidance and clarification from the relevant authorities. We will continue to monitor developments in this area and adjust our estimates throughout the year in 2018, as and if necessary, as additional guidance and clarification becomes available. See “— Critical Accounting Estimates — Income Taxes,” “Results of Operations — Overview — 2017 Compared to 2016 —Income Tax Benefit” and Note 15 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.

Critical Accounting Estimates

Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:

Property, Plant and Equipment. We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the years ended December 31, 2017 and 2016, we capitalized $69.4 million and $177.6 million, respectively, in replacements and betterments of our drilling fleet.

We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near term, contracted backlog of less than one year for a rig, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

 

•

dayrate by rig;

 

•

utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);

 

•

the per day operating cost for each rig if active, warm stacked or cold stacked;

 

•

the estimated annual cost for rig replacements and/or enhancement programs;

 

27

•

the estimated maintenance, inspection or other reactivation costs associated with a rig returning to work;

 

•

salvage value for each rig; and

 

•

estimated proceeds that may be received on disposition of each rig.

Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability-weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.

The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment.

Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, capital expenditures required due to advances in offshore drilling technology, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different.

During 2017, in response to continued depressed market conditions for the offshore contract drilling industry and our expectations that a market recovery is not likely to occur in the near term, we evaluated ten of our drilling rigs with indications that their carrying values may not be recoverable. As a result of these evaluations, we determined that the carrying values of one ultra-deepwater semisubmersible, one deepwater semisubmersible and one jack-up rig were impaired and recorded impairment losses of $71.3 million and $28.0 million during the second and fourth quarters of 2017, respectively.

During 2016, we evaluated 15 of our drilling rigs with indications that their carrying amounts may not be recoverable and recorded an aggregate impairment loss of $678.1 million, related to eight rigs including an $8.1 million impairment of rig spares and supplies. During 2015, we evaluated 25 of our drilling rigs with indications that their carrying amounts may not be recoverable and recorded an aggregate impairment loss of $860.4 million related to 17 drilling rigs. See “— Results of Operations — Overview — 2017 Compared to 2016 — Impairment of Assets” and “— Results of Operations —Overview — 2016 Compared to 2015 — Impairment of Assets” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, 2017, our deductibles for marine liability insurance coverage with respect to personal injury claims not related to named windstorms in the U.S.

 

28

Gulf of Mexico, which primarily result from Jones Act liability in the Gulf of Mexico, are $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. Our deductible for personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico is $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models.

The models used in estimating our aggregate reserve for personal injury claims include actuarial assumptions such as:

 

•

claim emergence, or the delay between occurrence and recording of claims;

 

•

settlement patterns, or the rates at which claims are closed;

 

•

development patterns, or the rate at which known cases develop to their ultimate level;

 

•

average, potential frequency and severity of claims; and

 

•

effect of re-opened claims.

The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

 

•

the severity of personal injuries claimed;

 

•

significant changes in the volume of personal injury claims;

 

•

the unpredictability of legal jurisdictions where the claims will ultimately be litigated;

 

•

inconsistent court decisions; and

 

•

the risks and lack of predictability inherent in personal injury litigation.

Income Taxes. We account for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material adverse impact on our financial results. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as net operating loss carryforwards, utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.

 

29

Certain of our international rigs are owned and operated, directly or indirectly, by DFAC. As of December 31, 2017, all unremitted earnings of DFAC have been deemed repatriated as a result of the Tax Reform Act, and U.S. taxes have been provided for them. We intend to indefinitely reinvest earnings of DFAC and its foreign subsidiaries to finance our foreign activities.

The Tax Reform Act requires a U.S. shareholder of a foreign corporation to include in income its global intangible low-taxed income, or GILTI. Due to the fact that the GILTI computation is dependent on contingent or future events that cannot reasonably be known, we have made the accounting policy decision, as permitted by U.S. GAAP, to account for U.S. tax on GILTI, should it be applicable, as a period cost in the period in which the tax would be incurred, as opposed to recognizing deferred taxes on the basis differences that are expected to affect the amount of GILTI.

In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment, and utilize outside consultants to assist us in the development of such transfer pricing methodologies. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts.

Results of Operations

Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics due to the nature of the revenue-earning process as it relates to the offshore drilling industry, over the operating lives of our drilling rigs. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.

Key performance indicators by equipment type are listed below.

 

		Year Ended December 31,
		2017				2016				2015
REVENUE-EARNING DAYS (1)
Floaters:
Ultra-Deepwater			2,546				2,074				2,690
Deepwater			874				844				1,339
Mid-Water			445				727				1,433
Jack-ups			282				149				909
UTILIZATION (2)
Floaters:
Ultra-Deepwater			59	%			51	%			64	%
Deepwater			41	%			34	%			52	%
Mid-Water			27	%			30	%			36	%
Jack-ups			61	%			8	%			42	%
AVERAGE DAILY REVENUE (3)
Floaters:
Ultra-Deepwater		$	428,200			$	477,000			$	497,700
Deepwater			231,600				304,600				409,800
Mid-Water			309,500				342,000				270,500
Jack-ups			74,900				202,700				93,400

 

(1)	A revenue-earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

 

30

(2)

Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet (including cold-stacked rigs, but excluding rigs under construction). As of December 31, 2017, our cold-stacked rigs included three ultra-deepwater semisubmersibles and two deepwater semisubmersibles. As of December 31, 2016, our cold-stacked rigs included four ultra-deepwater semisubmersibles, three deepwater semisubmersibles, and three mid-water semisubmersibles. As of December 31, 2015, our cold-stacked rigs consisted of one ultra-deepwater, two deepwater and four mid-water semisubmersible rigs and five jack-up rigs, which were being marketed for sale at that time.

(3)	Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue-earning day.

 

31

Comparative data relating to our revenues and operating expenses by equipment type are listed below.

 

		Year Ended December 31,
		2017				2016				2015
		(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater		$	1,090,139			$	989,158			$	1,339,059
Deepwater			202,329				256,997				548,667
Mid-Water			137,607				248,846				387,549
Total Floaters			1,430,075				1,495,001				2,275,275
Jack-ups			21,144				30,213				84,909
Total Contract Drilling Revenue		$	1,451,219			$	1,525,214			$	2,360,184
REVENUES RELATED TO REIMBURSABLE EXPENSES		$	34,527			$	75,128			$	59,209
CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater		$	561,505			$	494,510			$	620,122
Deepwater			115,350				148,992				277,779
Mid-Water			69,050				84,194				230,606
Total Floaters			745,905				727,696				1,128,507
Jack-ups			25,428				17,854				65,699
Other			30,631				26,623				33,658
Total Contract Drilling Expense		$	801,964			$	772,173			$	1,227,864
REIMBURSABLE EXPENSES		$	33,744			$	58,058			$	58,050
OPERATING INCOME (LOSS)
Floaters:
Ultra-Deepwater		$	528,634			$	494,648			$	718,937
Deepwater			86,979				108,005				270,888
Mid-Water			68,557				164,652				156,943
Total Floaters			684,170				767,305				1,146,768
Jack-ups			(4,284	)			12,359				19,210
Other			(30,631	)			(26,623	)			(33,658	)
Reimbursable expenses, net			783				17,070				1,159
Depreciation			(348,695	)			(381,760	)			(493,162	)
General and administrative expense			(74,505	)			(63,560	)			(66,462	)
Bad debt recovery			—				265				—
Impairment of assets			(99,313	)			(678,145	)			(860,441	)
Restructuring and separation costs			(14,146	)			—				(9,778	)
Gain (loss) on disposition of assets			10,500				(3,795	)			2,290
Total Operating Income (Loss)		$	123,879			$	(356,884	)		$	(294,074	)
Other income (expense):
Interest income			2,473				768				3,322
Interest expense			(113,528	)			(89,934	)			(93,934	)
Loss on extinguishment of senior notes			(35,366	)			—				—
Foreign currency transaction (loss) gain			(1,128	)			(11,522	)			2,465
Other, net			2,230				(10,727	)			873
(Loss) income before income tax benefit			(21,440	)			(468,299	)			(381,348	)
Income tax benefit			39,786				95,796				107,063
NET INCOME (LOSS)		$	18,346			$	(372,503	)		$	(274,285	)

 

32

Overview

2017 Compared to 2016

Operating Income (Loss). Operating results for 2017 increased $480.8 million compared to 2016, primarily due to a lower aggregate impairment loss recognized in 2017 ($578.8 million), combined with reduced depreciation expense ($33.1 million). Depreciation expense decreased compared to 2016, primarily due to a lower depreciable asset base, as a result of asset impairments in 2016 and 2017. These favorable variances were partially offset by a $99.8 million net reduction in rig operating results for our floater and jack-up rigs, $14.1 million in restructuring and severance costs recognized in 2017 and the absence of $14.6 million in net reimbursable revenue earned by the Ocean Endeavor in 2016.

Contract drilling revenue decreased $74.0 million during 2017 compared to 2016, primarily as a result of a lower average daily revenue earned by all rig types, partially offset by the favorable impact of an aggregate 353 incremental revenue-earning days. Total contract drilling expense for 2017 increased $29.8 million compared to 2016, reflecting higher amortized rig mobilization expense ($25.4 million) and incremental costs associated with the Pressure Control by the Hour^® program, or the PCbtH program, on our drillships ($27.8 million), partially offset by lower repair and maintenance costs ($15.2 million) and a net reduction in other rig operating and overhead costs ($8.2 million).

Interest Expense, Net of Amounts Capitalized. Interest expense increased $23.6 million during 2017 compared to 2016, primarily as a result of a $20.7 million reduction in interest capitalized during 2017 due to the completion of construction projects in 2016. Interest expense for 2017 also included incremental interest expense associated with newly-issued debt and subsequent debt redemption of existing debt in August 2017 ($4.0 million), which was partially offset by reduced interest expense associated with lower borrowings under our revolving credit agreement ($2.8 million). See “— Liquidity and Capital Resources — Senior Notes.”

Impairment of Assets. During 2017, we determined that the carrying values of one ultra-deepwater semisubmersible, one deepwater semisubmersible, and one jack-up rig were impaired. As a result, we recorded impairment losses of $71.3 million and $28.0 million during the second and fourth quarters of 2017, respectively. The deepwater semisubmersible rig was sold for scrap in January 2018, and the jack-up rig is being marketed for sale. During the second quarter of 2016, we recognized an aggregate impairment charge of $678.1 million with respect to the carrying values of two mid-water, three deepwater, and three ultra-deepwater semisubmersible rigs, including related rig spares and supplies. See “— Critical Accounting Estimates — Property, Plant and Equipment” and Note 1 “General Information —Assets Held for Sale” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

Restructuring and Separation Costs. During the fourth quarter of 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases. During 2017, we recognized $14.1 million in restructuring and other employee separation related costs, including $11.5 million related to a negotiated termination of our agency agreement in Brazil. See “Important Factors that May Impact Our Operating Results, Financial Condition or Cash Flows — 2017 Reduction Plan.”

Gain on Disposition of Assets. During 2017, we sold one ultra-deepwater floater, one deepwater floater, three mid-water floaters and one jack-up rig for scrap and recognized an aggregate pre-tax gain of $8.9 million on the sale of these rigs. In 2016, we sold one deepwater rig, three midwater rigs and four jack-ups for a net pre-tax loss of $4.0 million.

Loss on Extinguishment of Senior Notes. During the third quarter of 2017, we recorded a $35.4 million loss on extinguishment of $500.0 million aggregate principal amount of our senior notes that were to mature in 2019. See “— Liquidity and Capital Resources — Senior Notes.”

Other, net. During 2016, we sold our investment in privately-placed corporate bonds for a total recognized loss of $12.1 million.

Income Tax Benefit. During 2017 and 2016, we recorded net income tax benefits of $39.8 million and $95.8 million, respectively, on net losses of $21.4 million and $468.3 million, respectively. The variance in the income tax benefit

 

33

recognized between years is due to differences in the mix of our domestic and international pre-tax earnings and losses, including asset impairments taken during both 2017 and 2016 in various jurisdictions, as well as discrete tax items recorded in each period as a result of, including but not limited to, tax audits or assessments and filed or amended tax returns.

In addition, as a result of the Tax Reform Act that was signed into law on December 22, 2017, we recorded incremental income tax expense of $1.1 million, consisting of (i) a $75.4 million charge related to the immediate deemed repatriation of the previously deferred accumulated earnings of our non-U.S. subsidiaries and (ii) a $74.3 million benefit resulting from the remeasurement of our net U.S. deferred tax liability at the lower corporate income tax rate. During 2016, we recorded a $43.0 million reduction in income tax expense, primarily related to our Egyptian tax liability for uncertain tax positions related to the devaluation of the Egyptian Pound. See “Important Factors that May Impact Our Operating Results, Financial Condition or Cash Flows — Impact of Changes in Tax Laws or Their Interpretation” and Note 15 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.

2016 Compared to 2015

Operating Income (Loss). Operating results for 2016 decreased $62.8 million compared to 2015, primarily due to lower utilization of our rig fleet, which reduced both contract drilling revenue and expense. Our operating results for 2016 reflected an aggregate impairment charge of $678.1 million compared to impairment charges aggregating $860.4 million in 2015. As a result of the impairment charges in 2015 and 2016 and resulting lower depreciable asset base, depreciation expense decreased $111.4 million in 2016 compared to 2015.

Contract drilling revenue decreased $835.0 million, during 2016, compared to 2015, due to depressed market conditions in all floater markets and for our jack-up rig. Operating results for 2016 reflected an aggregate of 2,577 fewer revenue-earning days compared to 2015, and lower average daily revenue earned by our ultra-deepwater and deepwater floater fleets. Average daily revenue increased for our mid-water and jack-up fleets primarily due to the favorable settlement of a contractual dispute and receipt of loss-of-hire insurance proceeds, each in 2016.

Total contract drilling expense for 2016 decreased $455.7 million compared to 2015, reflecting our lower cost structure due to additional rigs idled, cold stacked or retired during 2015 and 2016, as well as the favorable impact of our cost control initiatives. The reduction in contract drilling expense during 2016 included lower costs associated with labor and personnel ($222.9 million), repairs and maintenance ($63.1 million), mobilization ($71.3 million), shorebase and operational support ($48.1 million), freight ($17.4 million), revenue-based agency fees ($16.1 million), inspections ($8.9 million), and other rig operating expenses ($7.9 million), including rig stacking costs and late start penalties recognized in 2015.

Impairment of Assets. During 2016, we recognized an aggregate impairment charge of $678.1 million related to the carrying values of eight rigs, including related rig spares and supplies. In 2015, we recorded an aggregate impairment loss of $860.4 million related to 17 of our rigs, consisting of two ultra-deepwater, one deepwater and nine mid-water floaters and five jack-up rigs. See “— Critical Accounting Estimates — Property, Plant and Equipment” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

Restructuring and Separation Costs. During the first quarter of 2015, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, which resulted in the recognition of $9.8 million in restructuring and other employee separation related costs in 2015.

Income Tax Expense. Our effective tax rate for 2016 was 20.5% compared to a 28.1% effective tax rate for 2015. The variance in the tax rate was due to differences in the mix of our domestic and international pre-tax earnings and losses, including asset impairments taken during both 2016 and 2015 in various jurisdictions, with differing tax consequences. The 2016 period was also favorably impacted by a $43.0 million adjustment, primarily related to our Egyptian tax liability for uncertain tax positions related to the devaluation of the Egyptian Pound.

 

34

Contract Drilling Revenue and Expense by Equipment Type

2017 Compared to 2016

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $101.0 million during 2017 compared to 2016, primarily as a result of 472 incremental revenue-earning days ($225.2 million), partially offset by lower average daily revenue earned ($124.2 million). Revenue-earning days increased primarily due to incremental revenue-earning days for the Ocean GreatWhite (351 days), which went on contract during the first quarter of 2017, and the Ocean BlackRhino, which was warm-stacked for much of 2016 (275 days) before commencing its current contract, and fewer days associated with downtime for repairs (89 days). The increase in 2017 revenue-earning days was partially offset by incremental downtime for the Ocean Monarch, which was in the shipyard for a survey and contract modifications during the first half of 2017 (168 days), and the absence of revenue-earning days for two cold-stacked rigs that had worked in 2016 (78 days). Average daily revenue decreased during 2017, primarily due to the absence of $40.0 million in demobilization revenue recognized in 2016 for the Ocean Endeavor and the effect of lower dayrates earned under new contracts for both the Ocean Monarch and Ocean BlackRhino during 2017, compared to 2016.

Contract drilling expense for our ultra-deepwater floaters increased $67.0 million during 2017, compared to 2016, primarily due to incremental contract drilling expense for the Ocean GreatWhite ($37.0 million), incremental costs associated with the PCbtH program on our drillships ($27.8 million), higher costs for rig mobilization ($14.0 million) and labor and personnel ($5.9 million), combined with a net increase in other rig operating costs ($2.5 million). These increased costs for our ultra-deepwater floaters were partially offset by a reduction in repair and maintenance expenses ($5.6 million) and costs associated with international shorebases and overhead costs ($14.5 million).

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $54.7 million in 2017, compared to 2016, primarily due to a reduction in average daily revenue earned ($63.8 million), partially offset by the effect of 30 incremental revenue-earning days ($9.2 million). Average daily revenue decreased during 2017, primarily as a result of a lower dayrate being earned by the Ocean Valiant under its current contract in the North Sea that commenced in the fourth quarter of 2016. Revenue-earning days increased primarily due to 218 incremental days for our active deepwater floaters, partially offset by 188 fewer days for the Ocean Victory, which had been under contract during 2016.

Contract drilling expense for our deepwater floaters decreased $33.6 million during 2017, compared to 2016, primarily due to a net reduction in costs associated with labor and personnel ($14.2 million), maintenance and repairs ($11.2 million), equipment rental ($2.6 million), freight ($1.4 million) and other rig operating and overhead costs ($4.2 million) attributable to various factors, including the cold stacking of rigs and implementation of cost control initiatives for our working rigs and shorebase operations in 2016.

Mid-Water Floaters. Revenue and contract drilling expense during 2017 for our mid-water floaters decreased $111.2 million and $15.1 million, respectively, compared to 2016. The decrease in revenue during 2017 resulted from 282 fewer revenue-earning days ($96.5 million), combined with a lower average daily revenue earned ($14.4 million). The decrease in revenue-earning days primarily related to the completion of the final contract for the Ocean Ambassador in March 2016 (78 days) and fewer days for both the Ocean Guardian, which was warm stacked between contracts for much of 2017 (166 days), and the Ocean Patriot (38 days), which commenced a shipyard project and survey in late 2017. The decrease in contract drilling expense was primarily due to reduced costs related to the Ocean Ambassador ($8.1 million), and a reduction in labor and personnel ($5.6 million) and other costs ($1.5 million) for the remainder of our mid-water rigs. Only two rigs remain in our mid-water fleet, both of which operated under contract for portions of 2017 and 2016, while the remainder of our mid-water fleet was cold stacked and has now been sold.

Jack-ups. Contract drilling revenue attributable to our current and previously-owned jack-up rigs decreased $9.1 million during 2017, compared to 2016. The Ocean Scepter, which had been idle since completion of its previous contract in 2016, returned to Mexico for a new contract in early 2017 and operated until November 2017 at a lower dayrate than previously earned ($4.1 million). The rig was relocated to the Gulf of Mexico in late 2017 and is currently being

 

35

marketed for sale. The decrease in contract drilling revenue also reflected the absence of $4.9 million in loss-of-hire insurance proceeds recognized in 2016.

Contract drilling expense for our jack-up rigs increased $7.6 million during 2017, compared to 2016, primarily due to higher costs incurred by the Ocean Scepter for labor and personnel ($6.4 million) and repairs ($1.7 million), partially offset by reduced costs associated with sold rigs ($0.5 million).

2016 Compared to 2015

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters during 2016 decreased $349.9 million compared to 2015, primarily as a result of 616 fewer revenue-earning days ($306.8 million), combined with lower average daily revenue earned ($43.1 million). Revenue-earning days for 2016 decreased primarily due to fewer revenue-earning days for cold-stacked rigs that had operated during 2015 (716 days) and the Ocean Clipper, which was sold in late 2015 (245 days), and unplanned downtime for repairs (22 days). The aggregate decrease in revenue-earning days was partially offset by incremental revenue-earning days for our drillships (185 days), and the Ocean Monarch, which was warm stacked for the first half of 2015 (182 days). Average daily revenue decreased in 2016 primarily due to lower amortized mobilization and contract preparation revenue compared to 2015.

Contract drilling expense for our entire ultra-deepwater floater fleet decreased $125.6 million during 2016, compared to 2015 and was net of incremental contract drilling expense of $74.9 million attributable to our four drillships and the Ocean GreatWhite, which was placed in service in late 2016. Contract drilling expense for our other ultra-deepwater floaters decreased $200.5 million during 2016, compared to 2015, reflecting lower expense for labor and personnel ($92.7 million), maintenance and inspections ($38.5 million), mobilization ($26.8 million), shorebase and operational support ($16.2 million), freight ($9.8 million), revenue-based agency fees ($8.2 million), and other rig operating and overhead costs ($8.3 million). These reductions in contract drilling expense were primarily due to lower costs for our cold-stacked rigs and the Ocean Clipper, as well as other cost reduction initiatives.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $291.7 million in 2016, compared to 2015, primarily due to 495 fewer revenue-earning days ($202.9 million), combined with a lower average daily revenue earned ($88.7 million). The net reduction in revenue-earning days in 2016 reflected 782 fewer days for cold-stacked rigs that had operated in 2015, partially offset by incremental revenue-earning days for other deepwater rigs with contracts that commenced in mid-2015 and in 2016. Average daily revenue decreased primarily as a result of lower amortized mobilization and contract preparation fees ($21.9 million), combined with lower dayrates earned by the Ocean Valiant and Ocean Apex during 2016 compared to 2015.

Contract drilling expense incurred by our deepwater floaters decreased $128.8 million during 2016, compared to 2015, primarily due to lower costs associated with cold-stacked rigs and cost control initiative in our onshore bases and corporate facilities. Compared to 2015, contract drilling expense in 2016 for our deepwater floaters reflected reductions in costs for labor and personnel ($51.3 million), mobilization of rigs ($29.5 million), repairs, maintenance and inspections ($18.7 million), shorebase and operational support ($15.1 million), revenue-based agency fees ($4.4 million), freight ($4.1 million) and other operating costs ($5.7 million).

Mid-Water Floaters. Revenue generated by our mid-water floaters during 2016 decreased $138.7 million compared to 2015, primarily due to 706 fewer revenue-earning days ($191.0 million), partially offset by higher average daily revenue earned ($52.0 million), which included a $36.0 million settlement received in connection with a contractual dispute with a former customer. Revenue-earning days decreased in 2016, primarily due to fewer mid-water floaters operating under contracts during 2016 (three rigs) compared to 2015 (nine rigs).

Contract drilling expense for our mid-water floaters decreased $146.4 million in 2016, compared to 2015, reflecting a reduction in costs attributable to rigs that have been retired ($109.0 million). Other cost reductions in 2016, compared to 2015, include lower costs for labor and personnel ($19.1 million), maintenance, repairs and inspections ($9.9 million),

 

36

shorebase and operational support ($6.1 million) and other ($2.3 million), primarily due to lower activity and cost control initiatives.

Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $54.7 million and $47.8 million, respectively, during 2016 compared to 2015. Revenue-earning days decreased by 760 days due to the cold stacking of three rigs that operated under contract during 2015 and an early contract termination for the Ocean Scepter in 2016.

Liquidity and Capital Resources

We principally rely on our cash flows from operations and cash reserves to meet our liquidity needs. We may also utilize borrowings under our $1.5 billion syndicated revolving credit agreement, or Credit Agreement. See “— Credit Agreement.”

Based on our cash available for current operations and contractual backlog of $2.4 billion, as of January 1, 2018, of which $1.2 billion is expected to be realized in 2018, we believe future capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See “— Sources and Uses of Cash — Capital Expenditures” and “Risk Factors — We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report.

To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each entity’s respective working capital requirements and capital commitments. At December 31, 2017, 2016 and 2015, we had cash available for current operations as follows:

 

		December 31,
		2017				2016				2015
		(In thousands)
Cash and cash equivalents		$	376,037			$	156,233			$	119,028
Marketable securities			—				35				11,518
Total cash available for current operations		$	376,037			$	156,268			$	130,546

A substantial portion of our cash flows has historically been invested in the enhancement of our drilling fleet, including $1.6 billion since 2015 for the construction of two newbuild rigs and other capital enhancement projects. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We also make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required. See “— Sources and Uses of Cash — Capital Expenditures.”

We pay dividends at the discretion of our Board of Directors, or Board, and any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. Our dividend policy may change from time to time, and there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Risk Factors — Although we have paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future and we can give no assurance as to the amount or timing of the payment of any future dividends” in Item 1A of this report, which is incorporated herein by reference. We did not pay any dividends in 2017 or 2016. We paid regular cash dividends in the aggregate amount of $68.6 million during 2015.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any of our outstanding common stock during 2017, 2016 or 2015.

 

37

During 2016, we entered into four sale-and-leaseback transactions for certain well control equipment on our drillships and received proceeds of $210.0 million. See “— Contractual Cash Obligations — Pressure Control by the Hour^®.”

We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control.

Sources and Uses of Cash

Our cash flow from operations and capital expenditures for each of the years in the three-year period ended December 31, 2017 was as follows:

 

		Year Ended December 31,
		2017				2016				2015
		(In thousands)
Cash flow from operations		$	493,808			$	646,554			$	736,427
Capital expenditures:
Drillship construction		$	—			$	55,426			$	454,093
Construction of ultra-deepwater floater			—				503,172				55,805
Rig equipment and replacement program			139,581				94,075				320,757
Total capital expenditures		$	139,581			$	652,673			$	830,655

Cash Flow from Operations. Cash flow from operations decreased approximately $152.7 million during 2017, compared to 2016, primarily due to lower cash receipts from contract drilling services ($245.0 million) and higher income taxes paid, net of refunds ($26.3 million), partially offset by a $118.6 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, repairs and maintenance, shorebase, overheads and other rig operating costs. The decline in both cash receipts and cash payments related to the performance of contract drilling services reflects continued depressed market conditions in the offshore drilling industry, as well as the positive results of our focus on controlling costs.

Cash flow from operations decreased approximately $89.9 million during 2016, compared to 2015, primarily due to lower cash receipts from contract drilling services ($704.9 million), partially offset by a $584.8 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, maintenance, mobilization, shorebase and operational support and other rig operating costs and lower income taxes paid, net of refunds ($30.2 million). The decline in both cash receipts from and cash payments related to contract drilling services reflects an aggregate decline in our contract drilling operations, as well as a lower cost structure and implementation of our cost control initiatives.

See “— Results of Operations — Years Ended December 31, 2017, 2016 and 2015.”

Capital Expenditures. As of the date of this report, we expect total capital expenditures for 2018 to aggregate approximately $220.0 million for our ongoing capital maintenance and replacement programs. We expect to fund our 2018 capital spending from our operating cash flows and our cash reserves.

Credit Agreement

Our Credit Agreement provides for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes maturing on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that mature on October 22, 2019. As of December 31, 2017, we had no borrowings

 

38