DIAMOND OFFSHORE DRILLING, INC. - Annual Report: 2011 (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, 2011

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  [ Ö ]    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  [ Ö ]

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  [ Ö ]    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  [  Ö  ]    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.    [ Ö ]

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  [ Ö ]

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 2012 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2011, 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, 2011

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PART I

Item 1.  Business.

General

Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a fleet of 49 offshore rigs, consisting of 32 semisubmersibles, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. See “ – Fleet Enhancements and Additions.” 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. We were incorporated in Delaware in 1989.

Our Fleet

Our diverse fleet enables us to offer a broad range of services worldwide in both the floater market (ultra-deepwater, deepwater and mid-water) and the non-floater, or jack-up, market.

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. While DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats, while 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 which 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 either an anchoring system or a dynamic-positioning 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 rigs under construction.

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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 rig, 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 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. Most 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.

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 reduced construction period than newbuild construction would require. Since December 2010, we have entered into three separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of three dynamically positioned, ultra-deepwater drillships with deliveries scheduled for the second and fourth quarters of 2013 and the second quarter of 2014.    We expect the aggregate cost for the three drillships, including commissioning, spares and project management, to be approximately $1.8 billion.

During 2009, we acquired two new-build ultra-deepwater, dynamically positioned, semisubmersible drilling rigs, the Ocean Courage and the Ocean Valor. Including our rig acquisitions in 2009 and our three drillships on order, we have purchased, ordered or upgraded eight units with capabilities in nominal water depths of 10,000 feet over the last five years.

In January 2012, we announced the construction of a moored semisubmersible rig that will be designed to operate in water depths up to 6,000 feet. The rig, to be named the Ocean Onyx, will be constructed utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Voyager. The rig will be constructed in Brownsville, Texas and is expected to be delivered in the third quarter of 2013 at an aggregate cost of approximately $300 million, including commissioning, spares and project management costs.

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

See “ – Fleet Status” for more detailed information about our drilling fleet as of January 30, 2012.

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Fleet Status

The following table presents additional information regarding our floater fleet at January 30, 2012:

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The following table presents additional information regarding our jack-up fleet at January 30, 2012:

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 15 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.

We believe our presence in multiple markets is valuable in many respects. For example, we believe that our experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and other international areas in which we operate, while production experience we have gained through our Brazilian and North Sea operations has potential application worldwide. Additionally, we believe our performance for a customer in one market segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.

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.

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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. See “Risk Factors – Our business involves numerous operating hazards which 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 – The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market,” “Risk Factors – Our drilling contracts may be terminated due to events beyond our control” and “Risk Factors – We have elected to 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 – 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 2011, 2010 and 2009, we performed services for 52, 46 and 47 different customers, respectively. During 2011, 2010 and 2009, 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 35%, 24% and 15% of our annual total consolidated revenues, respectively. OGX Petróleo e Gás Ltda., or OGX (a privately owned Brazilian oil and natural gas company), accounted for 14% of our annual total consolidated revenues in each of the years ended December 31, 2011 and 2010. No other customer accounted for 10% or more of our annual total consolidated revenues during 2011, 2010 or 2009.

Brazil is one of the most active floater markets in the world today. As of the date of this report, the greatest concentration of our operating assets is offshore Brazil, where we have 14 rigs currently working. Our contract backlog attributable to our expected operations offshore Brazil is $1.3 billion, $1.2 billion and $1.0 billion for the years 2012, 2013 and 2014, respectively, and $607.0 million in the aggregate for the years 2015 to 2016. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.

We principally market our services in North and South America through our Houston, Texas office. We market our services in other geographic locations principally from our regional offices in Aberdeen, Scotland and Perth, Australia. We provide technical and administrative support functions from our Houston office.

Competition

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share.    The offshore contract drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Some of our competitors may have greater financial or other resources than we do. We compete with offshore drilling contractors that together have almost 760 mobile rigs available worldwide.

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.

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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 and cyclical, with 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 90%, 81% and 66% of our total consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively. See “Risk Factors – A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations,” “Risk Factors – We may enter into drilling contracts that expose us to greater risks than we normally assume” 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.

Employees

As of December 31, 2011, we had approximately 5,300 workers, including international crew personnel furnished through independent labor contractors.

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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.

Lawrence R. Dickerson has served as our President and a Director since March 1998 and as our Chief Executive Officer since June 2008. Mr. Dickerson served as our Chief Operating Officer from March 1998 to June 2008. Mr. Dickerson served on the United States Commission on Ocean Policy from 2001 to 2004.

John M. Vecchio has served as Executive Vice President since August 2009. Mr. Vecchio previously served as our Senior Vice President – Technical Services from April 2002 to July 2009.

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

William C. Long has served as a Senior Vice President and our General Counsel and Secretary since October 2006. Mr. Long previously served as our Vice President, General Counsel and Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through February 2001.

Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.

Lyndol L. Dew has served as a Senior Vice President 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.

Access to Company Filings

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

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Item 1A.  Risk Factors.

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 we currently 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.

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

Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since our customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for our rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond our control, including:

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. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

In the aftermath of the Macondo well blowout in April 2010 and the subsequent investigation into the causes of the event, new rules for oil and gas operations on the Outer Continental Shelf, or OCS, have been implemented, including new standards for well design, casing and cementing and well control procedures, 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

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announced, including rules regarding employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. We are not able to predict the likelihood, nature or extent of additional rulemaking, nor are we 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 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.

As awareness of climate change issues increases, governments around the world are beginning to address the matter. 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 or regulations pertaining to climate change, 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 encouraging 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. In addition, new laws or regulations, including those that may come into effect following the Macondo incident, may require an increase in our capital spending for additional equipment to comply with such requirements and could also result in a reduction in revenues associated with downtime required to install such equipment.

Our business involves numerous operating hazards which 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 perils peculiar to marine operations, 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 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, 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.

Consistent with industry practice, our contracts with our customers generally contain contractual rights to indemnity from our customer for, among other things, pollution originating from the well, while we retain responsibility for pollution originating from the rig. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by us, our subcontractors and/or suppliers and our customers may dispute, or be unable to meet, their contractual indemnification obligations to us.

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, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Moreover, insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all. 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

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fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial position 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 those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all of these risks. In addition, no assurance can be made 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.

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, 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.

The United States Oil Pollution Act of 1990, or OPA ’90, and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ’90 and such similar legislation and related regulations impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. OPA ’90 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.

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

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

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.

Our industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. We cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. In response to a contraction in demand for certain types of our drilling rigs, primarily our shallow water jack-up rigs, we have cold stacked eight rigs as of the date of this report. We also may be required to idle additional rigs or to enter into lower rate contracts. 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.

Significant new rig construction and upgrades of existing drilling units could also intensify price competition. As of the date of this report, based on analyst reports, we believe that there are approximately 77 jack-up rigs and 96 floaters on order and scheduled for delivery between 2012 and 2018, with approximately half of these rigs scheduled for delivery in the next two years. The resulting increases in rig supply could be sufficient to depress rig utilization and intensify price competition from both existing competitors, as well as new entrants into the offshore drilling market. As of the date of this report, not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. The majority of the floaters

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on order are dynamically positioned drilling units, which further increases competition with our fleet in certain circumstances, depending on customer requirements. In Brazil, Petrobras, which accounted for approximately 35% of our consolidated revenues in 2011 and, as of February 1, 2012, accounted for approximately $3.7 billion of our contract drilling backlog through 2016 and to which ten of our floaters are currently contracted, has announced plans to construct locally 33 new deepwater drilling units to be delivered beginning in 2015. These new drilling units would increase rig supply and could intensify price competition in Brazil as well as other markets as they enter the market, would compete with, and could displace, our deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect our utilization rates, particularly in Brazil.

We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.

As of the date of this report, our contract drilling backlog was approximately $8.6 billion for contracted future work extending, in some cases, until 2019. Generally, 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 we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability to fulfill their contractual commitments to us may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.

We rely heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on our financial results.

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. In 2011, our five largest customers in the aggregate accounted for 62% of our consolidated revenues. We expect Petrobras and OGX, which accounted for approximately 35% and 14% of our consolidated revenues in 2011, respectively, to continue to be significant customers in 2012. Our contract drilling backlog, as of the date of this report, includes $1.3 billion, or 51% of our total contracted backlog for 2012, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil. While it is normal for our customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.

The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market.

The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit our profitability.

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

Our contracts for our drilling units 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 incurred by us. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond our control. 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 position, results of operations and cash flows.

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Our drilling contracts may be terminated due to events beyond our control.

Our customers may terminate some of our term drilling contracts if the drilling unit is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments 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 position, results of operations and cash flows. During periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets and the economic downturn. If our customers cancel some of their contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could materially and adversely affect our financial position, results of operations or cash flows.

A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations.

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

We are 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:

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 drilling industry. The actions of foreign governments may materially and adversely affect our ability to compete.

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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.

As of the date of this report, the greatest concentration of our operating assets outside the United States was offshore Brazil, where we had 14 rigs in our fleet either currently working or contracted to work during 2012.

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 position, results of operations and cash flows. For example, we currently operate, and expect to continue to operate, our drilling rigs offshore Mexico for PEMEX – Exploración y Producción, or PEMEX, the national oil company of Mexico. The terms of these contracts expose us to greater environmental liability than we normally assume, and provide that, among other things, each contract can be terminated by PEMEX on short notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place 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.

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. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.

Changes in 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 different jurisdictions. We are subject to the tax laws, tax regulations and income tax treaties within and between the countries in which we operate as well as countries in which we may be resident. 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.

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 if the terms of certain income tax treaties are interpreted in a manner that is adverse to 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.

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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 Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. We do not expect to provide for U.S. taxes on any future earnings generated by DOIL, 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 position, results of operations and cash flows.

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 position, results of operations and cash flows. While we take steps that we believe are appropriate 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.

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

We are, from time to time, involved in various litigation matters. 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 claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. 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.

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. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (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, we have three new ultra-deepwater drillships under construction which will require additional skilled personnel to operate. In addition, additional new capacity in the offshore drilling market could cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. The heightened competition for skilled personnel could materially and adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.

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

We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant at that time. Moreover, our dividend policy may change from time to time. We cannot assure you that we will continue to declare any special cash dividends at all or in any particular amounts. If in the future we pay special cash dividends less frequently or in smaller amounts, or cease to pay any special cash dividends, it could have a negative effect on the market price of our common stock. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities – Dividend Policy” included in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sources of Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Historical Cash Flows” included in Item 7 of this report.

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

From time to time we may undertake to add new capacity through conversions or upgrades to our existing rigs or through new construction, such as our three new, ultra-deepwater drillships under construction and our construction of the Ocean Onyx. 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 with equally favorable terms.

We have elected to 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 have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. 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 U.S. Gulf of Mexico cause significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows.

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

As of December 31, 2011, we had $1.5 billion in long-term debt. 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. Our debt levels and the terms of our indebtedness could potentially limit our liquidity and flexibility in obtaining additional financing, at rates which we consider reasonable or at all, and, thus, could limit our ability to pursue other business opportunities. In addition, our overall debt level and/or market conditions could lead the credit rating agencies to lower our corporate credit ratings. A downgrade 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. This could limit our ability to pursue other business opportunities.

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 50.4% of our outstanding shares of common stock as of February 16, 2012 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; HighMount Exploration & Production LLC, a wholly owned subsidiary engaged in exploration, production and marketing of natural gas and natural gas liquids; Boardwalk Pipeline Partners, LP, a 61% owned subsidiary engaged in the operation of interstate natural gas transmission pipeline systems; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation 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.

Item 1B.  Unresolved Staff Comments.

Not applicable.

Item 2.  Properties.

We own an eight-story office building totaling 170,000 square feet on 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located. We also own two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations, two buildings totaling 77,200 square feet and 11 acres of land in Macae, Brazil, for our South American operations and two buildings totaling 21,000 square feet and two acres of land in Ciudad del Carmen, Mexico, for our Mexican operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Indonesia, Norway, Malaysia, Singapore, Egypt, Equatorial Guinea, Angola, Vietnam and the U.K. to support our offshore drilling operations.

Item 3.  Legal Proceedings.

Not applicable.

Item 4.  Mine Safety Disclosures.

Not applicable.

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PART II

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

Price Range of Common Stock

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

As of February 16, 2012 there were approximately 203 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 2011, we paid regular cash dividends of $0.125 and special cash dividends of $0.75 per share of our common stock on February 28, June 1, September 1 and December 1. In 2010, we paid regular cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1. We also paid special cash dividends in 2010 of $1.875 per share of our common stock on March 1, $1.375 per share of our common stock on June 1, and $0.75 per share of our common stock on September 1 and December 1.

On February 1, 2012, we declared a regular cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the regular and special cash dividends are payable on March 1, 2012 to stockholders of record on February 13, 2012.

We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant at that time.

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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, a Peer Group Index and the Dow Jones U.S. Oil Equipment & Services over the five year period ended December 31, 2011.

Comparison of 2007 – 2011 Cumulative Total Return (1)

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

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Item 6.  Selected Financial Data.

The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. The selected consolidated financial data below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report. Historical data for the two annual periods ending on or prior to December 31, 2008 have been restated to reflect the effect thereon of the adoption on January 1, 2009 of an accounting standard that requires all convertible debt securities that may be settled by the issuer fully or partially in cash to be separated into a debt and an equity component. The bifurcation requirement applies to both newly issued debt and debt issuances outstanding for any time during the accounting periods for which financial statements are presented and has been applied retrospectively to the historical periods as of and for the years ended December 31, 2008 and 2007 presented below.

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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 provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling. Our fleet of 49 offshore drilling rigs consists of 32 semisubmersibles, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. In addition, in January 2012, we announced the construction of a moored semisubmersible rig that will be designed to operate in water depths up to 6,000 feet. The rig, to be named the Ocean Onyx, will be constructed utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Voyager.

Of our fleet, eight rigs are currently cold stacked, consisting of three intermediate semisubmersibles (one in the U.S. Gulf of Mexico, or GOM, and two in Malaysia) and five jack-up rigs (four in the GOM and one in Malaysia).

Overview

International Floater Market

Our floating rigs accounted for approximately 94% of our contract drilling revenue during the 2011. As of the date of this report, industry-wide floater utilization is reported to be greater than 90%, and, as of February 1, 2012, our floating rigs were committed for approximately 75% of the days remaining in 2012 and 54% of 2013.

Internationally, the ultra-deepwater and deepwater floater markets are generally strong and also show signs of further strengthening, particularly in the ultra-deepwater segment where we believe that there are few uncontracted rigs available to work in 2012. However, based on a December 2011 analyst report, there are 49 ultra-deepwater and deepwater floaters under construction, which are expected to enter the market in 2012 and 2013. Many of these floaters, primarily those scheduled for delivery in 2013, are not yet contracted for future work.

Market strength for ultra-deepwater and deepwater rigs varies among geographic regions. Upcoming drilling programs offshore Brazil will require a number of additional ultra-deepwater rigs. This demand may be met by rigs contructed domestically in Brazil, including 33 deepwater floaters ordered by Petrobras. However, additional demand for ultra-deepwater rigs could develop if Brazilian drilling programs, including those of Petrobras, are accelerated prior to delivery of domestically-constructed rigs. In addition, successful exploration and development programs in West Africa have given rise to a robust market for deepwater and ultra-deepwater rigs in that region.

Market strength for mid-water floaters is stable or improving depending on the geographic market. In the North Sea, the mid-water market is strong, with signs of increasing dayrates, and, in the Mediterranean region, demand remains solid. The Southeast Asia and Australia markets also remain steady.

Worldwide Jack-up Market

Four of our marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Of our two remaining marketed international jack-ups, one is currently working in Egypt, and the other, located in Montenegro, is actively seeking work.

GOM Floater and Jack-up Market

Deepwater drilling activity in the GOM, while strengthening, continues to be impacted by the issuance of oil and gas drilling permits for operations on the OCS, which has not yet returned to pre-Macondo levels. In addition, since the Macondo well blowout in 2010 more stringent and encompassing rules for oil and gas operations on the OCS have been implemented. As of the date of this report, we have two actively marketed rigs in the GOM, consisting of one semisubmersible and one jack-up rig. The Ocean Victory and Ocean Columbia are currently operating in the GOM, both with contract backlog extending into the second quarter of 2012. The construction of our deepwater, moored semisubmersible rig, the Ocean Onyx, is taking place in a shipyard in Brownsville, Texas.

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Contract Drilling Backlog

The following table reflects our contract drilling backlog as of February 1, 2012, October 17, 2011 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011) and February 1, 2011 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2010). Contract drilling backlog 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 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.

The following table reflects the amount of our contract drilling backlog by year as of February 1, 2012.

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The following table reflects the percentage of rig days committed by year as of February 1, 2012. 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 dates for the Ocean BlackHawk, Ocean BlackHornet, Ocean BlackRhino and the Ocean Onyx, which are all under construction.

General

The two most significant variables affecting our revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political, regulatory and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.

Demand affects the number of days our fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.

We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.

From time to time, we may receive fees from our customers for capital improvements to our rigs (either lump-sum or dayrate). We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

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As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, we expect contract drilling revenue in 2012 to decline from the levels attained in 2011. We also expect contract drilling revenue for some of our rigs to be lower as these rigs fulfill term commitments under contracts at lower dayrates than previously earned in 2011 and may not be able to benefit from higher dayrates that the market is currently bearing. See “Risk Factors – The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market” in Item 1A of this report.

We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.

Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. 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. We expect our labor and training costs to increase in 2012 as a result of increased hiring and training activities as we continue the process of crewing three new drillships. 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.

Our operating costs are also impacted by the regulatory environments in which we operate. The adoption of new regulations could result in additional inspection and certification costs, as well as require additional capital investment to comply with regulatory requirements. Accordingly, we cannot fully predict the financial impact of any new regulations that may arise relating to drilling activities in the GOM, or elsewhere in the world. New laws or regulations may require an increase in our capital spending for additional equipment to comply with such requirements. Our business could be negatively impacted by additional downtime which may be required to obtain necessary equipment and to install such equipment or to obtain the required inspections or certifications as prescribed under such regulations.

Operating expenses generally are not affected by changes in dayrates, and short-term reductions in utilization do not necessarily result in lower operating expenses. 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 the rig is to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, as incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods following capital upgrades.

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 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. 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 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 located in the U.K. and Norwegian sectors of the North Sea.

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During 2012, 11 of our rigs will require 5-year surveys and one of our U.K. rigs will require dry-docking for inspections. We expect these 12 rigs to be out of service for approximately 660 days in the aggregate. We also expect to spend an additional approximately 440 days during 2012 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects. 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 “ – Overview – Contract Drilling Backlog.”

We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows. Under our insurance policy that expires on May 1, 2012, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our insurance policy that expires on May 1, 2012, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for 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 $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under the current policy commences on May 1 of each 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. For the year ended December 31, 2011, we capitalized interest of $11.2 million on qualifying expenditures related to the construction of our three new drillships, beginning in August 2011. In addition, during 2012, we also expect to capitalize interest related to the construction of the Ocean Onyx.

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. Maintenance and routine repairs are charged to income currently while replacements and betterments, which 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, 2011 and 2010, we capitalized $269.5 million and $379.8 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $50 million per project.

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 cold stacking a rig or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize a 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 and estimates, we develop a matrix using several different utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. The sum of our utilization scenarios (which include active, warm stacked and cold stacked) and probability of occurrence scenarios both equal 100% in the aggregate. We reevaluate our cold-stacked rigs annually, and we update the matrices for each of our cold stacked rigs at each year end and modify our assumptions giving consideration to the length of time the rig has been cold stacked, the current and expected market for the type of rig and expectations of future oil and gas prices. Further, to test sensitivity, we consider the impact of a 5% reduction in assumed dayrates for the cold-stacked rigs (holding all other assumptions and estimates in the model constant). We would not necessarily record an impairment if the sensitivity analysis indicated potential cash flows would be insufficient to recover our carrying value. We would assess other qualitative factors including industry, regulatory and other relevant conditions to determine whether an impairment or further disclosure is warranted.

A summary of our cold stacked rigs evaluated for impairment at December 31, 2011, 2010 and 2009 was as follows:

We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these eight, seven and four rigs were not subject to impairment at December 31, 2011, 2010 and 2009, respectively.

Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.

Personal Injury Claims. Our deductibles for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims 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:

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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 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 Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. Accordingly, we have not made a provision for U.S. income taxes on approximately $1.7 billion of undistributed foreign earnings and profits. Although we do not intend to repatriate the earnings of DOIL 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 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.

We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense.

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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 among all our divisions and locations, including the nature of services provided and the type of customers for our services. 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, 2011, 2010 and 2009