DIAMOND OFFSHORE DRILLING, INC. - Annual Report: 2015 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2015

OR

For the transition period from                      to                     

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

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:

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  x    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  x

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  x    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  x    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.  x

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

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

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.

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2016 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2015, are incorporated by reference in Part III of this report.

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DIAMOND OFFSHORE DRILLING, INC.

FORM 10-K for the Year Ended December 31, 2015

TABLE OF CONTENTS

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PART I

General

Diamond Offshore Drilling, Inc. is a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 32 offshore drilling rigs, which includes four jack-up rigs that we are marketing for sale. Our fleet consists of 23 semisubmersibles, including the Ocean GreatWhite, which is under construction, five jack-ups and four dynamically positioned drillships, including the Ocean BlackLion which was delivered in the second quarter of 2015. See “– Our Fleet – Fleet Enhancements and Additions” and “– Our Fleet – Floater 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 diverse fleet enables us to offer a broad range of services worldwide, primarily in the floater market (ultra-deepwater, deepwater and mid-water).

Floaters. A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist 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:

See “– Fleet Enhancements and Additions” for further discussion of our rig under construction.

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Floater Fleet Status

The following table presents additional information regarding our floater fleet at February 16, 2016:

Jack-ups. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit in which a particular rig is able to operate is principally determined by the length of the rig’s legs. The rig hull includes the drilling equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull

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riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite. All of our jack-up rigs are equipped with a cantilever system that enables the rig to cantilever or extend its drilling package over the aft end of the rig.

As of February 16, 2016, the Ocean Scepter, a 350-foot jack-up drilling rig built in 2008, was operating offshore Mexico for PEMEX – Exploración y Producción, or PEMEX, under a long-term contract. In addition, we have four other jack-up rigs, which we are currently marketing for sale.

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, and otherwise by enhancing the capabilities of our existing rigs at a lower cost and shortened construction period than newbuild construction would require. Since 2009, commencing with the acquisition of two newbuild, ultra-deepwater semisubmersible rigs, the Ocean Courage and Ocean Valor, we have committed over $5.0 billion towards upgrading our fleet. In mid-2015, we took delivery of the Ocean BlackLion, the last of four ultra-deepwater drillships constructed in South Korea during our most recent fleet enhancement cycle. The Ocean GreatWhite remains under construction in South Korea with delivery of the new rig expected to occur in mid- 2016. Upon completion of acceptance testing, the rig is expected to commence drilling operations offshore Australia later this year.

We will 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 – Cash Flow and Capital Expenditures” in Item 7 of this report.

Pressure Control by the Hour. In February 2016, we entered into a ten-year agreement with GE Oil & Gas, or GE, to provide services with respect to certain blowout preventer and related well control equipment on our four newbuild drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the services agreement with GE, we will sell the equipment to a GE affiliate and will lease back such equipment over separate ten-year operating leases.

Markets

The principal markets for our offshore contract drilling services are the following:

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.

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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 fixed dayrate regardless of whether or not such drilling results in a productive well. Drilling contracts may 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 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,” “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,” “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,” “Risk Factors – We may enter into drilling contracts that expose us to greater risks than we normally assume” and “Risk Factors – We self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico” 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 2015, 2014 and 2013, we performed services for 19, 35 and 39 different customers, respectively. During 2015, 2014 and 2013, one of our customers in Brazil, Petróleo Brasileiro S.A., or Petrobras (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for 24%, 32% and 34% of our annual total consolidated revenues, respectively. During 2015, ExxonMobil and Anadarko each accounted for 12% of our annual consolidated revenues. No other customer accounted for 10% or more of our annual total consolidated revenues during 2015, 2014 or 2013. 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.

As of February 8, 2016, our contract backlog was $5.2 billion attributable to 11 customers. All four of our drillships are currently contracted to work in the GOM. As of February 8, 2016, contract backlog attributable to our expected operations in the GOM was $510.0 million, $653.0 million and $653.0 million for the years 2016, 2017 and 2018, respectively, and $626.0 million in the aggregate for the years 2019 to 2020 attributable to three

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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

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. The industry may also experience additional consolidation in the future, which could create other large competitors. Some of our competitors may have greater financial or other resources than we do. Based on industry data, as of the date of this report, there are approximately 840 mobile drilling rigs in service worldwide, including approximately 300 floater rigs.

The offshore contract drilling industry is influenced by a number of factors, including global economies and demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs.

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, at a cost that may be substantial, from one region to another. It is characteristic of the offshore contract drilling industry to move rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling units could also intensify 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 – Governmental laws and regulations, both domestic and international, may add to our costs or limit our drilling activity” and “Risk Factors – Compliance with or breach of environmental laws can be costly and could limit our operations” 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 79%, 85% and 89% of our total consolidated revenues for the years ended December 31, 2015, 2014 and 2013, 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,” “Risk Factors – We may enter into drilling contracts that expose us to greater risks than we normally assume,” “Risk Factors – We may be required to accrue additional tax liability on certain of our foreign earnings” and “Risk Factors – Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us” in Item 1A of this report, which are incorporated herein by reference.

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Employees

As of December 31, 2015, we had approximately 3,400 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 to serve until the next annual meeting of our Board of Directors, or 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. Mr. Edwards also served as Vice President for Production Enhancement of Halliburton Company from January 2008 through December 2009.

Lyndol L. Dew has served as our Senior Vice President – Worldwide Operations since September 2006. Previously, Mr. Dew served as our Vice President – International Operations from January 2006 to August 2006 and as our Vice President – North American Operations from January 2003 to December 2005.

Gary T. Krenek has served as our Senior Vice President and our Chief Financial Officer since October 2006. From March 1998 to 2006, Mr. Krenek served as our Vice President and Chief Financial Officer.

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.

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, a global diversified oilfield services company, from January 2011 through June 2014. From January 2010 through December 2011, Mr. Woll served as Vice President, Procurement at Halliburton Company.

Beth G. Gordon has served as our Controller and Chief Accounting Officer 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

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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.

Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below 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. If any of the following risks 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.

The worldwide demand for drilling services has declined significantly as a result of the decline in oil prices, which commenced during the second half of 2014 and has continued into 2016.

Demand for our drilling services depends in large part upon oil and natural gas industry 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 have declined precipitously and recently fell to a 12-year low of less than $30 per barrel. The dramatic reduction in commodity prices has caused a sharp decline in the demand for offshore drilling services, including services that we provide and adversely affected our results of operations and cash flows in 2015. A prolonged period of low oil prices would have a material adverse effect on many of our customers and, therefore, on our financial condition, results of operations and cash flows.

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

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An increase in commodity demand and prices will not necessarily result in an immediate increase in offshore drilling activity since our customers’ project development times, reserve replacement needs and expectations of future commodity demand, prices and supply of available competing rigs all combine to affect demand for our rigs.

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 oil and gas and a variety of political and economic factors. The level of offshore drilling activity is also 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 and newbuilds. 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 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, which could have a material adverse effect on our financial condition, results of operations and cash flows during these periods. Additionally, prolonged periods of low utilization and dayrates could also result in the recognition of 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

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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.

Recent new rig construction and upgrades of existing drilling rigs, cancelation or termination of contracts, as well as established rigs coming off contract during 2015, have contributed to the current oversupply of drilling rigs, intensifying price competition. Additional newbuild rigs entering the market are expected to further negatively impact rig utilization and intensify price competition as rigs are delivered. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview – Floater Markets” in Item 7 of this report.

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2015, one of our customers in Brazil, Petrobras, and our five largest customers in the aggregate accounted for 24% and 65%, respectively, of our annual total consolidated revenues. The loss of a significant 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, it could materially adversely affect our utilization rates in the affected market and also displace demand for our other drilling rigs and newbuilds as the resulting excess supply enters the market. While it is normal for our customer base to change over time as work programs are completed, the loss of, or a significant reduction in the number of rigs contracted with, any major customer may have a material adverse effect on our financial condition, results of operations and cash flows. 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 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 if the drilling rig is destroyed or lost, 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. Our drilling contract for the Ocean BlackLion, for example, requires us to successfully complete certain testing procedures for the rig’s equipment, including the blowout preventers and well control systems. We are currently undergoing the required testing. If these tests are not successfully completed, our customer may have the right to terminate the drilling contract or may request a renegotiation of the terms of the contract.

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, 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. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig, early termination of a contract in exchange for a lump sum margin payout and many other possibilities. Our contract backlog may be adversely impacted as a result of such contract renegotiations.

When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is adversely impacted, and we might not recover any compensation for the termination or any recovery we might

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obtain may not fully compensate us for the loss of the contract. In any case, the early termination of a contract may result in our rig being idle 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. In addition, if our customer cancels our contract or if we elect to terminate a contract due to the customer’s nonperformance and in either case we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or suspended for an extended period of time or if a contract is renegotiated, it could materially and adversely affect our financial condition, results of operations and cash flows.

Currently, our contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. We can provide no assurance that in such cases we will be able to ultimately execute a definitive agreement. In addition, for the reasons described above, we can provide no assurance that our customers will be willing or able to fulfill their contractual commitments to us.

Our inability to perform under our contractual obligations or to execute definitive agreements, or our customers’ inability or unwillingness to fulfill their contractual commitments to us, may 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.

We have a number of customer contracts that will expire in 2016 and 2017. 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. Given the highly competitive and historically cyclical 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 potentially substantially below, existing dayrates, or that have terms that are less favorable to us than our existing contracts or we may be unable to secure contracts for these rigs. This could have a material adverse effect on our financial condition, results of operations and cash flows.

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 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 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, a decision to retire or scrap the rig, changes in technology, market demand or market expectations, 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 12 drilling rigs and recorded impairment losses aggregating $1.0 billion, including $860.4 million recognized in 2015. 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.

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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 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, for which cold-stacking costs are typically substantially higher than for a jack-up rig or 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. A decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in contract drilling expense and could have a material adverse effect on our financial condition, results of operations and cash flows.

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

We pay dividends at the discretion of our Board of Directors, or Board. In recent years, we have paid both regular quarterly and special cash dividends, although we did not pay special cash dividends in 2015. In February 2016, we announced that we had discontinued our regular quarterly cash dividend. Our Board has adopted a policy of considering regular and special cash dividends, in amounts to be determined, on a quarterly basis. 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 may enter into drilling contracts that expose us to greater risks than we normally assume.

From time to time, we may enter into drilling contracts with national oil companies, government-controlled entities or others that expose us to greater risks than we normally assume, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to us, or if a termination payment is required, it may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. While we believe that the financial terms of these contracts and our operating safeguards in place may partially mitigate these risks, we can provide no assurance that the increased risk exposure will not have a material negative impact on our future operations or financial results.

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

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are subject to 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 and could have a material adverse effect on our financial condition, results of operations and cash flows.

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 and our earnings and cash flows from operations could be materially adversely affected.

Governmental laws and regulations, both domestic and international, may add to our costs or limit our drilling activity.

Our operations are affected from time to time in varying degrees by governmental laws and regulations. In addition to the specific regulatory risks discussed elsewhere in this Item 1A. “Risk Factors” section, our operations are subject to other laws, regulations and government policies worldwide. 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. 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. 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 5-year survey, or special survey, that are due every five years for each of our rigs. 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, inspection costs incurred and 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 5-year 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 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. 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.

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In the aftermath of the 2010 Macondo well blowout and subsequent investigation into the causes of the event, new rules were implemented for oil and gas operations in the GOM and in many of the international locations in which we operate, including new standards for well design, casing and cementing and well control procedures, equipment inspection and certifications, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations may continue to be announced, including rules regarding drilling systems and equipment, such as blowout preventer and well control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. Such new regulations could require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase our operating costs and cause downtime for our rigs if we are required to take any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled surveys or inspections, to meet any such new requirements. We are not able to predict the likelihood, nature or extent of additional rulemaking, and we are not able to predict the future impact of these events on our operations. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and enhanced permitting requirements, as well as escalating costs borne by our customers, could reduce exploration activity in the GOM and therefore demand for our services.

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 the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.

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.

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 a fixed 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 fluctuate based on events beyond our control. In addition, equipment repair and maintenance expenses fluctuate 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. Our inability to recover these increased or unforeseen costs from our customers could materially and adversely affect our financial condition, results of operations and cash flows.

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Rig conversions, upgrades or new-builds may be subject to delays and cost overruns.

From time to time, we add new capacity through conversions or upgrades to our existing rigs or through new construction, such as our harsh environment, ultra-deepwater semisubmersible rig, Ocean GreatWhite, which is currently under construction. Projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:

Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting in a loss of contract drilling backlog and revenue to us. If a drilling contract is terminated under these circumstances, we may not be able to secure a replacement contract or, if we do secure a replacement contract, it may not contain equally favorable terms. In addition, impairment write-offs could result if a rig’s carrying value becomes excessive due to spending over budget on a newbuild construction project or major rig upgrade.

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, damage to producing or potentially productive oil and gas formations, and 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, which could have a material adverse effect on our results of operations, financial condition and cash flows.

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

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of, our operations, and we may not be fully protected. Our contracts with our customers generally provide that we and our customers each assume liability for our respective personnel and property. Our contracts also generally provide that our customers assume most of the responsibility for and indemnify us against loss, damage or other liability resulting from, among other hazards and risks, pollution originating from the well and subsurface damage or loss, while we typically retain responsibility for and indemnify our customers against pollution originating from the rig. However, in certain drilling contracts we may not be fully indemnified by our customers for damage to their property and/or the property of their other contractors. In certain contracts we may assume liability for losses or damages (including punitive damages) resulting from pollution or contamination caused by negligent or willful acts of commission or omission by us, our suppliers and/or subcontractors, generally subject to negotiated caps on a per occurrence basis and/or on an aggregate basis for the term of the contract. In some cases, suppliers or subcontractors who provide equipment or services to us may seek to limit their liability resulting from pollution or contamination. 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.

Additionally, the enforceability of indemnification provisions in our contracts may be limited or prohibited by applicable law or 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 of 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, void or limited by public policy considerations, including when the cause of the underlying loss or damage is our gross negligence or willful misconduct, when punitive damages are attributable to us or when fines or penalties are imposed directly against us. 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. Current or future litigation in particular jurisdictions, whether or not we are a party, may impact the interpretation and enforceability of indemnification provisions in 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 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 such as 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. Accordingly, it is possible that our losses from the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.

We believe that the policy limit under 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. However, if an accident or other event occurs that exceeds our coverage limits or is not an insurable event under our insurance policies, or is not fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial condition and cash flows. 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.

Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.

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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 79%, 85% and 89% of our total consolidated revenues for 2015, 2014 and 2013, respectively, and include 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 risks of war, political disruption, civil disturbance, acts of terrorism, political 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) and changes in global trade policies. 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 the foregoing risks occur. In particular, the occurrence of any of these risks or any of the following events could materially and adversely impact our results of operations:

We are also subject to 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 worldwide anti-bribery laws. 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:

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Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international offshore drilling industry. The actions of foreign governments may materially and adversely affect our ability to compete.

In addition, the shipment of goods, including the movement of a drilling rig across international borders, subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws and regulations that differ in each of the countries in which we operate and often impose record keeping and reporting obligations. The laws and regulations concerning import/export activity and record keeping and reporting requirements are complex and change frequently. These laws and regulations may be enacted, amended, enforced and/or interpreted in a manner that could materially and adversely impact our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which may be outside of our control. Shipping delays or denials could cause unscheduled downtime for our rigs. 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.

Compliance with or breach of environmental laws can be costly and could limit our operations.

In the United States and in many of the international locations in which we operate, laws and regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. 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. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time they were performed.

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.

The application of these laws and regulations or the adoption of new laws and regulations could have a material adverse effect on our financial condition, results of operations and cash flows.

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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 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 factors.

We self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico.

Because the amount of insurance coverage available to us is limited, and the cost for such coverage is substantial, we self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts. If one or more named windstorms in the GOM cause significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows.

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 for those periods. These negative effects may include reduced or lost sales and revenues; costs associated with interruption in operations and with resuming operations; reduced demand for our services from customers that were similarly affected by these events; lost market share; late deliveries; uninsured property losses; inadequate business interruption insurance; employee evacuations; and an inability to retain necessary staff.

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 indefinitely reinvest future earnings of DFAC and its foreign subsidiaries to finance foreign activities. We do not expect to provide for U.S. taxes on any future earnings generated by DFAC and its foreign subsidiaries, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes that, if material, could have a material adverse effect on our financial condition, results of operations and cash flows.

Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.

Due to our international operations, we have experienced currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not effectively hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

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Acts of terrorism and other political and military events could adversely affect the markets for our drilling services.

Terrorist attacks and the continued threat of terrorism in the U.S. and abroad, the continuation or escalation of existing armed hostilities or the outbreak of additional hostilities could lead to increased political, economic and financial market instability and a downturn in the economies of the U.S. and other countries. A lower level of economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices, either of which could materially and adversely affect the market for our offshore drilling services, our dayrates or utilization and, accordingly, our financial condition, results of operations and cash flows. While we take steps that we believe are appropriately designed to secure our energy assets, there is no assurance that we can completely secure these assets, completely protect them against a terrorist attack or other political and military events or obtain adequate insurance coverage for such events at reasonable rates.

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 worldwide industry fleet increases (including due to the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could adversely affect our results of operations. As of the date of this report, the Ocean GreatWhite, our ultra-deepwater, semisubmersible rig, is under construction. This rig is not yet fully crewed and will require additional skilled personnel to operate. Additional new capacity in the offshore drilling market could also cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. 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 impact our financial condition, results of operations and cash flows by limiting our operations and further increasing our costs.

We rely on third-party suppliers, manufacturers and service providers to secure 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.

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 or equipment available to us and/or a significant increase in the price of such supplies and equipment, which could adversely impact our results of operations and cash flows.

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

As of December 31, 2015, we had approximately $0.3 million and $2.0 billion in short-term borrowings and senior debt, respectively, maturing at various times from 2019 through 2043. As of February 16, 2016, we had $305.0 million in Eurodollar loans outstanding and an additional $1.2 billion of availability under our revolving credit facility. We may incur additional indebtedness in the future, including indebtedness under our commercial paper program, and we may 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:

In addition, approximately $500.0 million of our long-term debt will mature over the next five years and will need to be paid or refinanced. We may not be able to refinance our maturing debt upon commercially reasonable terms, or at all, depending 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. Further, our liquidity may be adversely affected if we are unable to replace our revolving credit facility upon acceptable terms when it matures.

Our overall debt level and/or market conditions could lead credit rating agencies to lower our long-term and/or short-term corporate credit ratings. In January 2016, Moody’s Investor Services announced that it would be reviewing our long-term corporate credit and unsecured debt rating and short-term credit rating for commercial paper, which are currently Baa2 and Prime-2, respectively, for possible downgrade. Our current corporate credit rating is BBB+ and our short-term credit rating is A2 for Standard & Poor’s Ratings Services.

Downgrades in our corporate credit ratings could impact our ability to issue additional debt by raising the cost of issuing new debt. 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.

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In addition, our credit ratings are important to our ability to issue commercial paper at favorable rates of interest. A downgrade in our credit rating could increase the cost of borrowing or make the commercial paper market unavailable to us, which could increase our cost of capital. In addition, our access to funds under our commercial paper program is dependent on investor demand for our commercial paper. Disruptions and volatility in the global credit markets could limit the demand for our commercial paper or result in the need to offer higher interest rates to investors, which would result in increased expense and could adversely impact our liquidity.

Our revolving credit facility bears interest at variable rates. If market interest rates increase, debt service requirements on amounts outstanding under our revolving credit facility will increase. This would have an adverse effect on our results of operations and cash flows. Although we may employ hedging strategies such that a portion of the aggregate principal amount outstanding under this credit facility carries 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 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 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.

Unionization efforts and labor regulations in some of the countries in which we operate could materially increase our costs or limit our flexibility.

Some of our employees in non-U.S. markets are represented by labor unions and work under collective bargaining or similar agreements which are subject to periodic renegotiation. These negotiations could result in higher personnel expenses, other increased costs or increased operational restrictions. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we may be subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

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 16, 2016, 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. One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. 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.

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Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial Corporation, a 90% owned subsidiary engaged in commercial property and casualty insurance; Boardwalk Pipeline Partners, LP, a 51% owned subsidiary engaged in transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas; and Loews Hotels Holding Corporation, a wholly-owned subsidiary engaged in the operation of a chain of hotels. It is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or 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. We cannot assure you that these conflicts of interest will not materially adversely affect us.

Not applicable.

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, Egypt, Indonesia, Louisiana, Malaysia, Romania, Singapore, Thailand, Trinidad and Tobago, the U.K. and Vietnam to support our offshore drilling operations.

See information with respect to legal proceedings in Note 12 “Commitments and Contingencies” to our Consolidated Financial Statements in Item 8 of this report.

Not applicable.

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PART II

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.

As of February 16, 2016, there were approximately158 holders of record of our common stock. This number represents registered stockholders and does not include stockholders who hold their shares institutionally.

Dividend Policy

In 2015, we paid regular cash dividends of $0.125 per share of our common stock on March 2, June 1, September 1 and December 1. In 2014, we paid regular cash dividends of $0.125 and special cash dividends of $0.75 per share of our common stock on March 3, June 2, September 2 and December 1.

On February 8, 2016, we announced that we were discontinuing our regular cash dividend.

Our Board has adopted a policy of considering paying regular and special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a regular or special 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 continue to declare any regular or special cash dividends at all or in any particular amounts. See “Risk Factors – Although we have paid cash dividends in the past, we may not pay regular or special cash dividends in the future and we can give no assurance as to the amount or timing of the payment of any future regular or special cash dividends” in Item 1A of this report, which is incorporated herein by reference.

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CUMULATIVE TOTAL STOCKHOLDER RETURN

The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index and the Dow Jones U.S. Oil Equipment & Services index over the five year period ended December 31, 2015.

Comparison of 2011 – 2015 Cumulative Total Return ⁽¹⁾

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

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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.

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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 are a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 32 offshore drilling rigs that includes four jack-up rigs which we are marketing for sale. Our fleet consists of 23 semisubmersibles, including the Ocean GreatWhite, which is under construction, five jack-up rigs and four dynamically positioned drillships, including the last of our four newbuild drillships, the Ocean BlackLion, which was delivered in the second quarter of 2015. We expect our harsh environment, ultra-deepwater semisubmersible rig, the Ocean GreatWhite, to be delivered in mid-2016.

Market Overview

Market fundamentals in the oil and gas industry deteriorated further in the fourth quarter of 2015 and have continued to decline in 2016. In early January 2016, oil prices fell to a 12-year low below $30 per barrel, with some industry analysts predicting even lower commodity prices before any market recovery. Oil markets continue to be volatile due to a number of geopolitical and economic factors. These factors, combined with significant operating losses incurred during the fourth quarter of 2015 by some independent and national oil companies and exploration and production companies, have caused most of these companies to announce additional cuts to their already reduced 2016 capital spending plans, reflecting delays in planned drilling or exploration projects, and, in some cases, termination of projects altogether. Rig tenders are infrequent and have generally been limited to short-term or well-to-well work not commencing until 2017 or later. There have been very few rig tenders thus far in 2016.

The offshore floater market is currently faced with an oversupply of drilling rigs, which thus far has only been slightly abated by the cold stacking and retirement of rigs. The number of available rigs continues to grow as contracted rigs come off contract and newbuilds are delivered, increasing competition. Competition for the limited number of drilling jobs continues to be intense with some operators bidding multiple rigs on the same job, in some cases, bidding rigs of both higher and lower specifications. Operators are also continuing to attempt to sublet previously contracted rigs for which capital spending programs have been delayed or canceled. Industry analysts have predicted that the offshore contract drilling market may remain depressed with further declines in dayrates and utilization likely in 2016 and 2017.

As a result of the depressed market conditions and continued pessimistic outlook for the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling contracts. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig, early termination of a contract in exchange for a lump sum margin payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to terminate the contract early after specified notice periods, sometimes resulting in no payment to us or sometimes resulting in a contractually specified termination amount, which may not fully compensate us for the loss of the contract. During depressed market conditions, 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. Particularly during depressed market conditions, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is also adversely impacted. 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” and “– Contract Drilling Backlog” below.

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Our results of operations and cash flows for the year ended December 31, 2015 have been materially impacted by depressed market conditions in the offshore drilling industry. We currently expect that these adverse market conditions will continue for the foreseeable future. The continuation of these conditions for an extended period could result in more of our rigs being without contracts and/or cold stacked or scrapped and 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 2015, we recognized an aggregate impairment loss of $860.4 million, including an impairment loss of $499.4 million recognized in the fourth quarter of 2015. See “– Results of Operations – Years Ended December 31, 2015, 2014 and 2013 – Overview – 2015 Compared to 2014 – 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

As of February 16, 2016, 17 of our rigs were not subject to a drilling contract with a customer, including 14 rigs that have been cold stacked. Of the cold-stacked rigs, four jack-up rigs are currently being marketed for sale. The previously cold-stacked jack-up rig Ocean Titan was sold in February 2016. See “– Contract Drilling Backlog” for future commitments of our rigs during 2016 through 2020.

Although these general market conditions impact all segments of the offshore drilling market, the following discussion addresses market conditions within segments of the floater market.

Floater Markets

Ultra-Deepwater and Deepwater Floaters. Globally, the ultra-deepwater and deepwater floater markets continue to be depressed. Diminished or nonexistent demand, combined with an oversupply of rigs has caused floater dayrates to decline significantly. Offshore drilling contractors have been approached by customers with binding contracts, who have sought to and have successfully renegotiated such contracts at lower rates to obtain some financial relief in the current market, and, in some cases, have terminated contracts with and without compensation to the associated drilling contractor. Industry analysts expect offshore drillers to continue to scrap older, lower specification rigs; however, newer and higher specification rigs have not been immune to the recycling trend. In addition, industry analysts predict that the number of uncontracted floaters may more than double by the end of 2016.

Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in both the ultra-deepwater and deepwater markets. In an effort to manage the oversupply of rigs and potentially avoid the cost of cold stacking newly-built rigs, which, in the case of dynamically-positioned rigs, can be significant, several drilling contractors have exercised options to delay the delivery of rigs by the shipyard or have exercised their right to cancel orders due to the late delivery of rigs. As of the date of this report, based on industry data, there are approximately 54 competitive, or non-owner-operated, newbuild floaters on order, 32 of which are not yet contracted for future work. In addition, based on industry reports, there are currently 20 newbuild floaters scheduled for delivery in 2016, of which only four rigs have been contracted for future work; however, industry analysts predict that delivery dates may shift as newbuild owners negotiate with their respective shipyards.

Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have been adversely impacted by (i) lower demand, (ii) declining dayrates, (iii) increased regulatory requirements, including more stringent design requirements for well control equipment, which could significantly increase the capital needed to comply with design requirements that would permit such rigs to work in U.S. waters, (iv) the challenges experienced by lower specification units in this segment as a result of more complex customer specifications, and (v) the intensified competition resulting from the migration of some deepwater and ultra-deepwater units to compete against mid-water units. To date, the mid-water market has seen the highest number of cold-stacked and scrapped rigs. Since 2012, we have sold 12 of our mid-water rigs for scrap. As market conditions remain challenging, we expect higher specification rigs to take the place of lower specification units, where possible, leading to additional lower specification rigs being cold stacked or ultimately scrapped.

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Contract Drilling Backlog

The following table reflects our contract drilling backlog as of February 16, 2016 (based on contract information known at that time), October 1, 2015 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2015), and February 9, 2015 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2014). 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 and adding one-half of any potential rig performance bonuses. 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. 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.

The following table reflects the amount of our contract drilling backlog by year as of February 16, 2016.

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The following table reflects the percentage of rig days committed by year as of February 16, 2016. 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). Total available days have been calculated based on the expected final commissioning date for the Ocean GreatWhite, which is under construction.

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 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

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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 new and seasoned employees can be significant. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment and the regions in which our rigs are working.

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. 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 5-year survey will vary from year to year, as well as from quarter to quarter.

In addition, operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs generally older than 15 years that are located in the United Kingdom sector of the North Sea.

During 2016, we expect to spend approximately 535 days for the mobilization of rigs and contract acceptance testing, including days associated with mobilization and acceptance testing for the Ocean GreatWhite (approximately 90 days), which is under construction and expected to be delivered in mid-2016 and rig modifications and acceptance testing for the Ocean BlackRhino, which is scheduled to begin operating under a new contract in January 2017 (approximately 155 days). We expect the Ocean Endeavor to be unavailable through mid-2016 (approximately 135 days) as it demobilizes out of the Black Sea. 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.”

In April 2015, the Bureau of Safety and Environmental Enforcement (an agency established by the U.S. Department of the Interior that governs the offshore drilling industry on the Outer Continental Shelf) announced proposed rules that, when enacted, will include more stringent design requirements for well control equipment used in offshore drilling operations. Based on our assessment of the proposed rules, we believe that we may need to incur significant capital costs to comply with the additional design requirements to enable our cold-stacked mid-water semisubmersibles to return to work in U.S. waters.

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the GOM. If a named windstorm in the GOM 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 insurance policy, we carry physical damage insurance for certain losses other than those caused by named windstorms in the GOM 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, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of

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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, including for personal injury claims, are $25.0 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.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use, which is expected to continue after delivery of the rigs from the shipyard and until the user acceptance phase of each project is completed. For the year ended December 31, 2015, we capitalized interest of $16.3 million on qualifying expenditures related to the construction of the Ocean GreatWhite and the Ocean BlackLion, until it was placed in service in June 2015. We will continue capitalizing interest on qualifying expenditures during 2016 for the Ocean GreatWhite, which is expected to be completed in mid-2016.

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.

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, 2015 and 2014, we capitalized $262.4 million and $546.0 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:

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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 and inspection costs, are estimated using historical data adjusted for known developments 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, 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 2015, in response to pending regulatory requirements in the GOM, as well as the continued deterioration of the market fundamentals in the oil and gas industry, including the dramatic decline in oil prices, significant cutbacks in customer capital spending plans and contract cancelations by customers, 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, consisting of two ultra-deepwater, one deepwater and nine mid-water floaters and five jack-up rigs. In the third quarter of 2014, we recognized an impairment loss of $109.5 million in connection with our management’s decision to retire and scrap six mid-water semisubmersible rigs. See “– Results of Operations – Years Ended December 31, 2015, 2014 and 2013 –Overview – 2015 Compared to 2014 – Impairment of Assets,” “– Results of Operations – Years Ended December 31, 2015, 2014 and 2013 – Overview – 2014 Compared to 2013 – Impairment of Assets” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.

Personal Injury Claims. Our deductibles for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $25.0 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

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of claims which 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:

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

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 utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.

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 indefinitely reinvest future earnings of DFAC and its foreign subsidiaries to finance foreign activities. Accordingly, we have not made a provision for U.S. income taxes on approximately $2.0 billion of undistributed foreign earnings and profits. Although we do not intend to repatriate the earnings of DFAC and have not provided U.S. income taxes for such earnings, except to the extent that such earnings were immediately subject to U.S. income taxes, these earnings could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practicable to estimate this potential liability.

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

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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.

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

Years Ended December 31, 2015, 2014 and 2013

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Overview

2015 Compared to 2014

Operating (Loss) Income. We incurred an operating loss of $294.1 million in 2015 compared to operating income of $572.6 million in 2014. Our operating results for 2015 reflected an aggregate impairment loss of $860.4 million, $9.8 million in restructuring and severance costs, and a $96.2 million net reduction in rig operating results for our combined floater fleet and jack-up rigs, compared to 2014. Depreciation expense increased $36.7 million in 2015, compared to 2014, due to a higher depreciable asset base in 2015, including the Ocean Apex and two newbuild drillships, which were placed in service in December 2014, partially offset by the absence of depreciation for certain of our rigs that were impaired or sold during late 2014 and in 2015.

Total contract drilling revenue declined $376.9 million, or 14%, during 2015 compared to 2014, primarily due to a $782.9 million decrease in revenue earned by our combined mid-water and jack-up fleets, partially offset by an aggregate $405.9 million increase in revenue earned by our ultra-deepwater and deepwater floaters. Our results for 2015 reflected an aggregate 2,800 fewer revenue earning days, compared to 2014, primarily, due to the cold stacking of additional rigs, rig sales and incremental downtime between contracts, partially offset by incremental revenue generating days for our newly constructed and upgraded or enhanced rigs.

Total contract drilling expense for 2015 decreased $295.8 million, or 19%, compared to the prior year, primarily due to lower rig utilization, combined with our efforts to control costs. Contract drilling expense for 2015, compared to 2014, reflected lower costs for labor and personnel ($165.8 million), repairs and maintenance ($70.1 million), inspections ($17.2 million), freight ($17.9 million), rig insurance ($9.7 million) and a net decrease in other rig operating costs, including costs associated with our international shorebases, overhead costs and revenue-based agency fees ($72.6 million), partially offset by higher rig mobilization expense ($57.6 million).

Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our mid-water semisubmersible rigs, all of which were sold by the end of 2015. As a result of this decision, we recognized an impairment loss of $109.5 million during 2014 to write down the aggregate net book value of these rigs to their estimated recoverable amounts. During 2015, in response to pending regulatory requirements in the GOM, as well as the continued deterioration of the market fundamentals in the oil and gas industry, we determined that the carrying value of 17 of our rigs, consisting of two ultra-deepwater, one deepwater and nine mid-water floaters and five jack-up rigs were impaired and, therefore, recorded an aggregate impairment loss of $860.4 million for the year ended December 31, 2015. 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. In response to the continued decline in the offshore drilling market, we have reviewed our cost and organization structure. As a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities. During the year ended December 31, 2015, we recognized $9.8 million in restructuring and employee separation related costs on behalf of separated employees.

Interest Expense, Net of Amounts Capitalized. Interest expense increased $31.9 million during 2015, compared to 2014, primarily as a result of less interest capitalized during 2015 ($44.3 million) due to the completion of five qualifying construction projects in 2014 and 2015. This increase was partially offset by a $12.3 million reduction in interest expense for 2015, primarily due to the repayment of two tranches of our senior notes in September 2014 and July 2015, reduced by additional interest expense on short-term borrowings during 2015.

Income Tax Expense. Our effective tax rate for 2015 was 28.1%, compared to a 24.9% effective tax rate for 2014. The higher effective tax rate in 2015 was due to differences in the mix of our domestic and international

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pre-tax earnings and losses, including asset impairments taken during both 2015 and 2014 in various jurisdictions, with differing tax consequences. The 2014 period also included the reversal of $55.4 million of reserves for uncertain tax positions in various foreign jurisdictions which were settled in our favor or for which the statute of limitations had expired, compared to a similar reversal of $9.5 million in 2015.

2014 Compared to 2013

Operating Income. Operating income decreased $229.0 million, or 29%, during 2014, compared to 2013, primarily due to a $106.5 million, or 4%, reduction in contract drilling revenue combined with the negative effects of a $109.5 million impairment loss recognized in the third quarter of 2014, higher depreciation ($68.4 million) and higher general and administrative expenses ($17.0 million). During 2014, we recognized incremental depreciation expense on a higher depreciable asset base, compared to 2013, which included the following newly constructed rigs placed in service during 2014: Ocean Onyx (January 2014), Ocean BlackHawk (February 2014) and Ocean BlackHornet, Ocean BlackRhino and Ocean Apex (December 2014). General and administrative costs for 2014 reflected higher employee compensation and professional fees than those incurred in the prior year, primarily related to compensation of and termination benefits paid to certain of our current and former key executives. These negative effects were partially offset by a $48.9 million reduction in contract drilling expense and the absence of a $22.5 million charge for an uncollectible receivable incurred in 2013.

Contract drilling revenue for our deepwater and mid-water fleets decreased $122.8 million and $121.1 million, respectively, during 2014, compared to 2013, primarily as a result of 324 and 217 fewer revenue earning days, respectively, combined with the effect of a lower average daily revenue earned by our mid-water floater fleet. In contrast, contract drilling revenue earned by our ultra-deepwater floaters and jack-up rigs increased $133.1 million and $4.4 million, respectively, during 2014, compared to 2013, primarily due to higher average daily revenue earned by both our ultra-deepwater and jack-up fleets despite an aggregate 345-day reduction in revenue earning days during 2014.

Total contract drilling expense during 2014 decreased by $48.9 million, or 3%, compared to 2013, primarily due to the cold stacking or scrapping of rigs, contract preparation work and lower repairs and maintenance expenses, partially offset by increased costs associated with the operation of the Ocean BlackHawk and Ocean Onyx beginning in the first quarter of 2014.

Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our mid-water semisubmersibles. As a result of this decision, we recognized an impairment loss of $109.5 million to write down the aggregate net book value of these rigs to their estimated recoverable amounts.

Bad Debt Expense. During 2013, based on our assessment of the financial condition of two of our customers, Niko Resources Ltd. and OGX Petróleo e Gás Ltda., and our expectations regarding the probability of collection of amounts due to us from them, we recorded $22.5 million in bad debt expense

Interest Expense. Interest expense increased $37.2 million during 2014, compared to 2013, primarily due to incremental interest expense of $34.4 million, primarily related to the issuance of $1.0 billion in senior unsecured notes in November 2013 and a $13.6 million decrease in capitalized interest as a result of rig construction projects completed in 2014, partially offset by reduced interest expense related to $250.0 million in senior debt that we repaid in 2014. The increase in interest expense was also partially offset by the reversal of $6.2 million of expense in 2014 associated with changes in uncertain tax positions in the Brazil and Mexico tax jurisdictions, combined with the absence of $5.9 million of interest expense recognized in the prior year associated with uncertain tax positions in the Mexico tax jurisdiction.

Income Tax Expense. Our effective tax rate for 2014 was 24.9%, compared to a 29.1% effective tax rate for 2013. The lower effective tax rate in 2014 was due to differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operated. The lower

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effective tax rate in the current period was also due to the reversal of $55.4 million of reserves for uncertain tax positions in various foreign jurisdictions which were settled in our favor or for which the statute of limitations had expired. During 2013, our effective tax rate was negatively impacted by a provision of $56.9 million related to an uncertain tax position in Egypt, partially offset by the recognition of the impact of The American Taxpayer Relief Act of 2012, which reduced 2013 income tax expense by $27.5 million.

Contract Drilling Revenue and Expense by Equipment Type

2015 Compared to 2014

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $351.5 million during 2015, compared to 2014, primarily as a result of 539 incremental revenue earning days ($247.6 million), combined with higher average daily revenue earned ($103.9 million). Total revenue earning days increased in 2015, primarily due to incremental revenue earning days for our newbuild drillships (621 additional days), the Ocean Endeavor offshore Romania (149 additional days) and the Ocean Monarch offshore Australia (105 additional days), partially offset by fewer revenue earning days for our other ultra-deepwater floaters (336 fewer days), including the early termination of drilling contracts for the Ocean Baroness and Ocean Clipper. Average daily revenue increased in 2015, compared to 2014, primarily due to revenue associated with the operation of three additional drillships in 2015 and the Ocean Endeavor, including higher amortized mobilization and contract preparation revenue, and a favorable dayrate adjustment for the Ocean Courage.

Contract drilling expense for our ultra-deepwater floaters increased $83.5 million during 2015, compared to 2014, reflecting incremental costs for our newbuild drillships ($153.4 million), partially offset by lower aggregate costs for our other ultra-deepwater floaters ($69.9 million). The decrease in contract drilling expense in 2015 for our other ultra-deepwater floaters reflected lower costs for labor and personnel ($42.6 million), repairs and maintenance ($11.5 million), rig mobilization and inspections ($2.3 million) and other rig operating costs ($13.5 million).

Deepwater Floaters. Revenue generated by our deepwater floaters increased $54.4 million in 2015, compared to 2014, primarily due to 133 incremental revenue earning days ($54.5 million). The increase in revenue earning days during 2015 resulted from incremental operating days for four of our deepwater floaters after prolonged periods of nonproductive time for planned upgrades and surveys, as well as warm-stacking between contracts (501 incremental days), partially offset by fewer revenue earning days due to the cold stacking of the Ocean Star (233 days) and additional non-revenue earning days for rig mobilization and repairs (135 additional days).

Contract drilling expense for our deepwater floaters decreased an aggregate $14.3 million in 2015, compared to 2014, reflecting lower labor and personnel related costs ($10.0 million), repairs and maintenance ($17.0 million) and other rig operating costs ($7.5 million). These reductions in contract drilling expense in 2015, compared to 2014, were partially offset by higher amortized rig mobilization expense ($20.2 million), primarily related to drilling rigs that returned to service in 2015.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $689.3 million in 2015, compared to 2014, primarily due to 2,536 fewer revenue earning days ($688.1 million) combined with lower average daily revenue earned ($1.2 million). The reduction in revenue earning days during 2015 resulted from the cold stacking or retirement of twelve mid-water rigs (2,638 fewer days) and the idling of the Ocean Guardian and Ocean Quest, between contracts (288 fewer days), partially offset by incremental revenue earning days for the upgraded Ocean Patriot operating in the North Sea (296 additional days) and the Ocean Ambassador, which is expected to complete its contract offshore Mexico in the first quarter of 2016 (94 additional days).

Contract drilling expense for our mid-water floaters decreased $304.5 million in 2015, compared to 2015, primarily due to reduced operating costs for our idled, cold-stacked and retired mid-water rigs ($344.1 million), partially offset by incremental operating costs for the Ocean Patriot ($36.9 million).

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Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $93.6 million and $45.5 million, respectively, during 2015, compared to 2014, primarily due to reduced utilization for five rigs that were under contract in 2014, but were cold stacked and marketed for sale at the end of 2015. Contract drilling revenue for 2015 was also negatively impacted by a negotiated dayrate reduction for our remaining actively marketed jack-up rig, the Ocean Scepter.

2014 Compared to 2013

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $133.1 million during 2014, compared to 2013, primarily due to higher average daily revenue earned ($219.0 million), partially offset by the unfavorable effect of 241 fewer revenue earning days ($85.9 million). Average daily revenue increased primarily due to several of our ultra-deepwater floaters earning higher dayrates during 2014, compared to those earned in 2013, as well as incremental amortization of $50.6 million in mobilization and contract preparation fees, including amounts recognized in connection with contracts for the Ocean Monarch in Indonesia ($11.3 million), the Ocean Endeavor in Romania ($22.4 million) and the Ocean Clipper in Colombia ($8.8 million). Revenue earning days decreased during 2014, compared to 2013, primarily due to incremental downtime for planned inspections and shipyard projects (366 additional days), including the Ocean Confidence life-extension project, non-revenue earning days between contracts (241 additional days) and rig mobilizations (95 additional days), partially offset by a reduction in unscheduled downtime for repairs (273 fewer days) and 189 revenue earning days for the Ocean BlackHawk, which was placed in service in 2014.

Contract drilling expense for our ultra-deepwater fleet decreased $2.1 million in 2014, compared to 2013, as incremental operating costs for the Ocean BlackHawk ($44.8 million) were mostly offset by lower operating costs for the Ocean Confidence ($48.3 million) as a result of the rig’s life-extension project, which began in the second quarter of 2014.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $122.8 million during 2014 compared to 2013, primarily due to 324 fewer revenue earning days ($130.6 million), partially offset by higher average daily revenue earned ($7.8 million), which reflected an increase in amortized mobilization and contract preparation revenue associated with the Ocean America’s Australia contract. Revenue earning days decreased primarily due to unplanned downtime attributable to the warm stacking of rigs between contracts (533 additional days) and incremental downtime for planned surveys and shipyard projects (85 additional days) and rig mobilizations (46 additional days), partially offset by 333 incremental revenue earning days for the Ocean Onyx during 2014.

Contract drilling expense incurred by our deepwater floaters increased $24.2 million during 2014, compared to 2013, primarily due to incremental operating costs for the Ocean Onyx ($31.5 million), costs associated with a five-year survey for the Ocean Alliance ($18.2 million) and the mobilization of the Ocean Star to the GOM, where it is currently cold stacked ($8.8 million). The increase in contract drilling expense in 2014 was partially offset by a reduction in costs for international shorebase locations ($9.7 million), labor and personnel ($6.0 million), repairs and maintenance ($9.2 million), inspections ($4.0 million), agency fees ($1.8 million), and other rig-related costs ($3.5 million), primarily as a result of lower rig utilization compared to 2013.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $121.1 million during 2014, compared to 2013, primarily as a result of 217 fewer revenue earning days ($62.2 million) and lower average daily revenue earned ($58.9 million). The decline in revenue earning days for 2014 reflected a 652-day increase in unplanned downtime, primarily due to the cold stacking of rigs, unpaid equipment repairs and downtime between contracts, partially offset by a 435-day reduction in planned downtime for shipyard projects and regulatory inspections. Average daily revenue earned during 2014 decreased, compared to 2013, primarily due to lower amortized mobilization and contract preparation revenue ($35.9 million) and a significantly lower dayrate earned by the Ocean Quest operating in Vietnam, partially offset by higher dayrates earned by our rigs operating in the North Sea during 2014.

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Contract drilling expense for our mid-water fleet decreased $69.4 million during 2014, compared to 2013, primarily due to reduced costs for cold stacked rigs and retired rigs ($46.3 million) and the Ocean Patriot, which was out of service until the fourth quarter of 2014 for an enhancement project and contract preparation activities ($9.6 million). In addition, contract drilling expense incurred by our actively-marketed mid-water fleet in 2014, compared to 2013, reflected lower aggregate costs for shipyard projects and regulatory inspections ($24.4 million) and mobilization of rigs ($14.5 million), partially offset by higher labor and personnel costs ($23.4 million).

Jack-ups. Contract drilling revenue for our jack-up fleet increased $4.4 million during 2014, compared to 2013, primarily due to an increase in average daily revenue earned ($13.7 million), as a result of higher dayrates earned by several of our jack-up rigs during 2014, partially offset by 104 fewer revenue earning days compared to 2013 ($9.3 million). Contract drilling expense decreased $3.9 million in 2014, compared to 2013, primarily due to lower costs associated the mobilization of rigs ($6.6 million), partially offset by higher labor and personnel-related costs ($3.4 million).

Liquidity and Capital Resources

We have historically relied principally on our cash flows from operations and cash reserves to meet liquidity needs and fund our cash requirements. However, in 2015, we also utilized short-term borrowings under our $1.5 billion syndicated revolving credit agreement, or Credit Agreement, and issued commercial paper under our commercial paper program to meet our short-term liquidity needs. At February 16, 2016, we had $305.0 million in Eurodollar loans outstanding under the Credit Agreement[, which will mature on February 29, 2016]. See “– Credit Agreement, Commercial Paper Program and Senior Notes.”

Based on our cash available for current operations and contractual backlog of $5.2 billion, as of February 8, 2016, of which $1.6 billion is expected to be realized in 2016, we believe future capital spending, including the final installment due on the Ocean GreatWhite and debt service requirements, will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement and/or the issuance of commercial paper. See “– Cash Flow and Capital Expenditures – Contractual Cash Obligations – Rig Construction” 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.”

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC, and, as a result of our intention to indefinitely reinvest the earnings of DFAC and its foreign subsidiaries to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. See “– Market Overview – Critical Accounting Estimates – Income Taxes.” 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., or DODI, to meet each entity’s respective working capital requirements and capital commitments.

At December 31, 2015, 2014 and 2013, we had cash available for current operations, including cash reserves of DFAC, as follows:

A substantial portion of our cash flows has been invested in the enhancement of our drilling fleet, including $3.8 billion since 2013 for the construction of five newbuild rigs, the major upgrade of two semisubmersible rigs

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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 “– Cash Flow and Capital Expenditures – Contractual Cash Obligations – Rig Construction.” We pay dividends at the discretion of our Board of Directors, or Board. During the three-year period ended December 31, 2015, we paid regular and special cash dividends totaling $206.9 million and $829.9 million, respectively. Our Board has adopted a policy of considering paying cash dividends, in amounts to be determined, on a quarterly basis. 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 of Directors considers relevant at that time. Our dividend policy may change from time to time, and there can be no assurance that we will continue to declare any cash dividends at all or in any particular amounts.

On February 8, 2016, we announced that we were discontinuing our quarterly regular cash dividend. See “Risk Factors – Although we have paid cash dividends in the past, we may not pay regular or special cash dividends in the future and we can give no assurance as to the amount or timing of the payment of any future regular or special cash dividends” in Item 1A of this report, which is incorporated herein by reference.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. During 2014, we repurchased 1,895,561 shares of our outstanding common stock at a cost of $87.8 million. In addition, Loews has informed us that, depending on market and other conditions, it may, from time to time, purchase shares of our common stock in the open market or otherwise. During the years ended December 31, 2015, 2014 and 2013, Loews purchased 1,134,827, 1,879,600 and 0, shares of our common stock, respectively.

During the three-year period ended December 31, 2015, our primary source of cash was an aggregate $2.8 billion generated from operating activities, $1.1 billion net proceeds from the sale or maturity of marketable securities in 2014 and 2013, net of purchases, $987.8 million net proceeds from the issuance of senior notes in 2013, $286.6 million net proceeds/repayments from the issuance of commercial paper in 2015 and an aggregate $25.7 million from the sale of 12 drilling rigs during 2015 and 2014. Cash usage during the same period was primarily for capital expenditures ($3.8 billion), payment of dividends and anti-dilution payments to stock plan participants ($1.0 billion), long-term debt maturities ($250.0 million in each of 2015 and 2014) and the acquisition of treasury stock ($87.8 million) in 2014.

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.

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Cash Flow and Capital Expenditures

Our cash flow from operations and capital expenditures for each of the years in the three-year period ended December 31, 2015 were as follows:

Cash Flow. Cash flow from operations decreased approximately $256.4 million during 2015, compared to 2014, primarily due to lower cash receipts from contract drilling services ($444.8 million), partially offset by a $144.4 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, maintenance, mobilization and other rig operating costs and lower income taxes paid, net of refunds ($44.0 million). The decline in cash receipts from and cash payments related to contract drilling services both reflect an aggregate decline in our contract drilling operations, as well as our efforts to control costs.

Cash flow from operations decreased approximately $73.2 million during 2014, compared to 2013, primarily due to higher cash payments for contract drilling expenses ($77.0 million) and higher interest paid on our senior notes ($50.8 million) related to interest paid on $1.0 billion in debt issued in November 2013 and an early interest payment for our 4.875% senior notes due July 1, 2015. The increase in cash outflows for 2014 was partially offset by lower income taxes paid, in the U.S. federal jurisdiction, net of refunds, and a slight increase in cash receipts from contract drilling services ($6.5 million).

See “– Results of Operations – Years Ended December 31, 2015, 2014 and 2013.”

Capital Expenditures. As of the date of this report, we expect capital expenditures for 2016 to aggregate approximately $675.0 million, of which we expect to spend approximately $525.0 million to complete construction of the Ocean GreatWhite and an estimated $150.0 million for our ongoing capital maintenance and replacement programs. See “– Contractual Cash Obligations – Rig Construction.” We expect to fund our 2016 capital spending from the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available to and cash reserves of DODI, as well as borrowings under our Credit Agreement or issuance of commercial paper.

Contractual Cash Obligations – Rig Construction. As of the date of this report, we have one rig, the Ocean GreatWhite, under construction in Ulsan, South Korea, for which we are obligated under a construction agreement with Hyundai Heavy Industries Co., Ltd. Construction of the Ocean GreatWhite continues with delivery expected in mid-2016. The estimated total project cost, including shipyard costs, capital spares, commissioning, project management and shipyard supervision, but excluding capitalized interest, is $764.0 million, of which $241.5 million has been incurred as of December 31, 2015. See Note 12 “Commitments and Contingencies” to our Consolidated Financial Statements included in Item 8 of this report for more information about this project.

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We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2015, except for those related to our direct rig operations, which arise during the normal course of business.

Credit Agreement, Commercial Paper Program and Senior Notes

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, 2015, there were no loans or letters of credit outstanding under the Credit Agreement, and we were in compliance with all covenant requirements under the Credit Agreement.

Our Credit Agreement also provides liquidity for our payment obligations in respect of notes issued under our commercial paper program. Under our commercial paper program, we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion,and, unless we change the terms of the program, the aggregate amount of commercial paper notes and total loans and letters of credit outstanding under the Credit Agreement at any time will not exceed $1.5 billion. At December 31, 2015, we had $286.6 million in commercial paper notes outstanding with a weighted average interest rate of 0.86% and a weighted average remaining term of 5.8 days that were repaid in January 2016. As of February 16, 2016, we had no commercial paper notes outstanding.

During February 2016, we borrowed $305.0 million in Eurodollar loans under our Credit Agreement, which bear interest at 1.565% and mature on February 29, 2016. As of February 16, 2016, we had an additional $1.2 billion available under the Credit Agreement.

As of December 31, 2015, we had an aggregate $2.0 billion in long-term, unsecured senior notes outstanding, of which $500.0 million will mature in 2019 and the remainder will mature at various times beginning in 2023.

See Note 10 “Credit Agreement and Senior Notes” to our Consolidated Financial Statements in Item 8 of this report.

Credit Ratings. In January 2016, Moody’s Investor Services announced that it would be reviewing our long-term corporate credit and unsecured debt rating and short-term credit rating for commercial paper, which are currently Baa2 and Prime-2, respectively, for possible downgrade. Our current corporate credit rating is BBB+ and our short-term credit rating is A2 for Standard & Poor’s Ratings Services. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. A downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue, and could restrict our access to our commercial paper program and capital markets and our ability to raise additional debt or rollover existing maturities. 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.

Contractual Cash Obligations

The following table sets forth our contractual cash obligations at December 31, 2015.

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Except for the construction contracts discussed above and referred to in the preceding table, we had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2015, except for those related to our direct rig operations, which arise during the normal course of business.

In February 2016, we entered into a ten-year agreement with GE Oil & Gas, or GE, to provide services with respect to certain blowout preventer and related well control equipment on our four newbuild drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the services agreement with GE, we will sell the equipment to a GE affiliate for an aggregate $210.0 million and will lease back such equipment over separate ten-year operating leases. We do not expect to realize any gain or loss on these sale and leaseback transactions. Future commitments for the full term under the services agreement and leases are estimated to aggregate approximately $650.0 million.

Other Commercial Commitments – Letters of Credit

We were contingently liable as of December 31, 2015 in the amount of $71.6 million under certain performance, supersedeas, bid, tax and customs bonds and letters of credit. Agreements relating to approximately $64.0 million of performance, tax, supersedeas, court and customs bonds can require collateral at any time. As of December 31, 2015, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.

Off-Balance Sheet Arrangements

At December 31, 2015 and 2014, we had no off-balance sheet debt or other off-balance sheet arrangements.

Other

Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations. Currency environments in which we have significant business operations include Brazil, the U.K., Australia and Mexico. We may, if possible, attempt to minimize our currency exchange risk by seeking international contracts payable to us in local currency in amounts equal to our estimated operating costs payable in local currency, with the balance of the contract payable in U.S. dollars. At present, however, only a limited number of our contracts are payable both in U.S. dollars and the local currency.

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Historically, to the extent that we have not been able to cover our local currency operating costs with customer payments in the local currency, we have also utilized foreign currency forward exchange, or FOREX, contracts to reduce our currency exchange risk. We currently have no outstanding FOREX contracts.

We record currency transaction gains and losses as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. Gains and losses arising from the settlement of our FOREX contracts that have been designated as cash flow hedges are reported as a component of “Contract drilling, excluding depreciation” expense in our Consolidated Statements of Operations.

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

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These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:

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The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we may refer to reports published by third parties that purport to describe trends or developments in energy production or drilling and exploration activity. We do so for the convenience of our investors and potential investors and in an effort to provide information available in the market intended to lead to a better understanding of the market environment in which we operate. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

New Accounting Pronouncements

For a discussion of recent accounting pronouncements, which are not yet effective, and their effect on our financial position, results of operations and cash flows, see Note 1 “General Information – Recent Accounting Pronouncements” to our Consolidated Financial Statements in Item 8 of this report.

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The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –Forward-Looking Statements” in Item 7 of this report.

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2015 and 2014, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.

Interest Rate Risk

We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. Our investments in marketable securities are primarily in fixed maturity securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one-year period.

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on December 31, 2015 and 2014, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

Our long-term debt, as of December 31, 2015 and 2014, is denominated in U.S. dollars. Our existing debt has been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $112.7 million and $176.8 million as of December 31, 2015 and 2014, respectively. A 100-basis point decrease would result in an increase in market value of $131.3 million and $210.6 million as of December 31, 2015 and 2014, respectively.

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Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into FOREX contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for most of our contracts is the average spot rate for the contract period. As of December 31, 2015, we had no FOREX contracts outstanding. At December 31, 2014, we have presented the fair value of our outstanding FOREX contracts as a current liability of $(5.4) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report.

The following table presents our exposure to market risk by category (interest rates and foreign currency exchange rates):

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Diamond Offshore Drilling, Inc. and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Diamond Offshore Drilling, Inc. and subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

February 19, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Diamond

Offshore Drilling, Inc. and Subsidiaries Houston, Texas

We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 19, 2016 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Houston, Texas

February 19, 2016

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DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)