Edgar Filing: DIAMOND OFFSHORE DRILLING INC

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[ X ]

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

For the fiscal year ended December 31, 2012

[ ]

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

For the transition period from ............... to ....................

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)


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

15415 Katy Freeway

Houston, Texas 77094

(Address and zip code of principal executive offices)

(281) 492-5300

(Registrant’s telephone number, including area code)

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


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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ 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):


Large accelerated filer [ Ö ]		Accelerated filer [ ]
Non-accelerated filer [ ]		Smaller reporting company [ ]
(Do not check if a smaller reporting company)

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.


As of June 29, 2012		$4,075,545,066

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

As of February 18, 2013	Common Stock, $0.01 par value per share	139,031,570 shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2013 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2012, are incorporated by reference in Part III of this report.

DIAMOND OFFSHORE DRILLING, INC.

FORM 10-K for the Year Ended December 31, 2012

TABLE OF CONTENTS


		Page No.
Cover Page			1

Document Table of Contents			2

Part I
Item 1.	Business		3

Item 1A.	Risk Factors		9

Item 1B.	Unresolved Staff Comments		18

Item 2.	Properties		18

Item 3.	Legal Proceedings		19

Item 4.	Mine Safety Disclosures		19

Part II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		19

Item 6.	Selected Financial Data		21

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		41

Item 8.	Financial Statements and Supplementary Data		44

	Consolidated Financial Statements		46
	Notes to Consolidated Financial Statements		51

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		79

Item 9A.	Controls and Procedures		79

Item 9B.	Other Information		80

Part III
	Certain information called for by Part III Items 10, 11, 12, 13 and 14 has been omitted as the Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.
Part IV
Item 15.	Exhibits and Financial Statement Schedules		80

Signatures			81

Exhibit Index			82

PART I

Item 1.

Business.

General

Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a fleet of 44 offshore drilling rigs, consisting of 32 semisubmersibles, seven jack-ups and five dynamically positioned drillships, four of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second and fourth quarters of 2014. Our semisubmersible fleet includes the Ocean Onyx and Ocean Apex, two moored semisubmersible rigs designed to operate in water depths up to 6,000 feet, which are under construction and expected to be delivered in the third quarter of 2013 and the second quarter of 2014, respectively. As of December 31, 2012, three of our semisubmersible rigs and one jack-up rig were being marketed for sale. See “ – Fleet Enhancements and Additions” and “ – Fleet Status.”

Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. 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. Although DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats; non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between locations.

A drillship is an adaptation of a maritime vessel 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 DP system similar to those used on semisubmersible rigs.

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


Category	Rated Water Depth ^(a) (in feet)	Number of Units in Our Fleet
Ultra-Deepwater	7,501 to 12,000	12^(b)
Deepwater	5,000 to 7,500	7 ^(c)
Mid-Water	400 to 4,999	18 ^(d)

^(a)

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

^(b)

Includes four drillships under construction.

^(c)

Includes the Ocean Apex and Ocean Onyx, currently under construction.

^(d)

Includes the Ocean Epoch, Ocean New Era and Ocean Whittington, which are being marketed for sale.

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

Jack-ups. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit in which a particular rig is able to operate is principally determined by the length of the rig’s legs. The rig hull includes the drilling equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite. All of our jack-up rigs are equipped with a cantilever system that enables the rig to 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. We have contracted with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of four dynamically positioned, ultra-deepwater drillships, including the Ocean BlackLion, which we announced in May 2012. We expect the aggregate cost for the four drillships, including commissioning, spares and project management costs, to be approximately $2.6 billion.

In August 2012, we began construction of the Ocean Apex, a moored semisubmersible rig designed to operate in water depths up to 6,000 feet, for an estimated aggregate cost of $370 million, including commissioning, spares and project management costs. The Ocean Apex is being constructed in Singapore utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Bounty, which was cold stacked in 2009.

Construction of the Ocean Onyx is underway in Brownsville, Texas. The rig is expected to be delivered for an estimated aggregate cost of approximately $310 million, including commissioning, spares and project management costs.

In February 2013, we announced that one of our mid-water floaters, the Ocean Patriot, will undergo enhancements to enable the rig to work in the North Sea at an estimated aggregate cost of approximately $120 million. We expect the enhancement project to begin during the third quarter of 2013 with completion expected in early 2014.

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

See “ – Fleet Status” for more detailed information about our drilling fleet.

Fleet Status

The following table presents additional information regarding our floater fleet at January 28, 2013:


Type and Name	Rated Water Depth (in feet)	Attributes	Year Built/ Redelivered (a)	Current Location (b)	Customer (c)

Ultra-Deepwater Semisubmersibles (7):
Ocean Valor	10,000	DP; 6R; 15K; 4M	2009	Brazil	Petrobras
Ocean Courage	10,000	DP; 6R; 15K; 4M	2009	Brazil	Petrobras
Ocean Confidence	10,000	DP; 6R; 15K; 4M	2001	Angola	Cobalt
Ocean Monarch	10,000	15K; 4M	2008	Indonesia	Niko Resources
Ocean Endeavor	10,000	15K; 4M	2007	Egypt	Burullus
Ocean Rover	8,000	15K; 4M	2003	Malaysia	DODI/Survey
Ocean Baroness	8,000	15K; 4M	2002	Brazil	Petrobras

Ultra-Deepwater Drillships (5):
Ocean BlackLion	12,000	DP; 7R; 15K; 5M	Q4 2014	South Korea	Under construction
Ocean BlackRhino	12,000	DP; 7R; 15K; 5M	Q2 2014	South Korea	Under construction
Ocean BlackHornet	12,000	DP; 7R; 15K; 5M	Q4 2013	South Korea	Under construction/Anadarko ^(d)
Ocean BlackHawk	12,000	DP; 7R; 15K; 5M	Q2 2013	South Korea	Under construction/Anadarko ^(d)
Ocean Clipper	7,875	DP; 15K	1997	Brazil	Petrobras

Deepwater Semisubmersibles (7)
Ocean Apex	6,000	15K	Q2 2014	Singapore	Under construction
Ocean Onyx	6,000	15K	Q3 2013	GOM	Under construction/Apache ^(d)
Ocean Victory	5,500	15K	1997	GOM	Eni US
Ocean America	5,500	15K	1988	Australia	Apache
Ocean Valiant	5,500	15K	1988	Equatorial Guinea	Hess
Ocean Star	5,500	15K	1997	Brazil	OGX
Ocean Alliance	5,250	DP; 15K	1988	Brazil	Petrobras

Mid-Water Semisubmersibles (18):
Ocean Winner	4,000		1976	Brazil	Petrobras
Ocean Worker	4,000		1982	Brazil	DODI/Survey
Ocean Quest	4,000	15K	1973	Brazil	DODI/Survey
Ocean Yatzy	3,300	DP	1989	Brazil	Petrobras
Ocean Patriot	3,000	15K	1983	Vietnam	Idemitsu
Ocean General	3,000		1976	Indonesia	Salamander
Ocean Yorktown	2,850		1976	Mexico	PEMEX
Ocean Concord	2,300		1975	Brazil	Petrobras
Ocean Lexington	2,200		1976	Brazil	OGX
Ocean Saratoga	2,200		1976	GOM	BP
Ocean Guardian	1,500	15K	1985	North Sea/U.K.	Shell
Ocean Princess	1,500	15K	1975	North Sea/U.K.	EnQuest
Ocean Vanguard	1,500	15K	1982	North Sea/Norway	Statoil
Ocean Nomad	1,200		1975	North Sea/U.K.	Fairfield Cedrus
Ocean Ambassador	1,100		1975	GOM	Actively marketing
Ocean Epoch	3,000		1977	Malaysia	Held for sale ^(e)
Ocean Whittington	1,650		1974	GOM	Held for sale ^(e)
Ocean New Era	1,500		1974	GOM	Held for sale ^(e)

Attributes

Dynamically Positioned/Self-Propelled

2 Seven ram blow out preventers

Four Mud Pumps

Six ram blow out preventer

15K

15,000 psi well control system

Five Mud Pumps

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

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

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

(d)	Rig is contracted for future work upon completion of commissioning; unit is currently expected to commence drilling operations in the GOM.

(e)	Rig is being marketed for sale.

The following table presents additional information regarding our jack-up fleet at January 28, 2013:


Type and Name	Rated Water Depth (a) (in feet)	Attributes	Year Built	Current Location (b)	Customer (c)

Jack-ups (7):
Ocean Scepter	350	IC; 15K	2008	Mexico	PEMEX
Ocean Titan	350	IC; 15K	1974	Mexico	PEMEX
Ocean King	300	IC	1973	GOM	In transit/actively marketing
Ocean Nugget	300	IC	1976	Mexico	PEMEX
Ocean Summit	300	IC	1972	Mexico	PEMEX
Ocean Spur	300	IC	1981	Ecuador	Saipem ^(d)
Ocean Spartan	300	IC	1980	GOM	Held for sale ^(e)


	Attributes
IC = Independent-Leg Cantilevered Rig		15K = 15,000 psi well control system

(a)	Rated water depth reflects the operating water depth capability for each drilling unit.

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

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

(d)	Rig is currently under a bareboat charter until the third quarter of 2014.

(e)	Rig is being marketed for sale.

Markets

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

•

South America, principally offshore Brazil;

•

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

•

the Middle East, including Kuwait, Qatar and Saudi Arabia;

•

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

•

East and West Africa;

•

the Mediterranean Basin, including Egypt; and

•

the Gulf of Mexico, including the U.S. and Mexico.

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 area enables us to better understand that customer’s needs and better serve that customer in different market areas 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.

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,” “Risk Factors – We may enter into drilling contracts that expose us to greater risks than we normally assume” 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 – Market Overview – Contract Drilling Backlog” in Item 7 of this report, which is incorporated herein by reference.

Customers

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2012, 2011 and 2010, we performed services for 35, 52 and 46 different customers, respectively. During 2012, 2011 and 2010, 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 33%, 35% and 24% 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 12%, 14% and 14% of our annual total consolidated revenues for the years ended December 31, 2012, 2011 and 2010, respectively. No other customer accounted for 10% or more of our annual total consolidated revenues during 2012, 2011 or 2010. See “Risk Factors — 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” in Item 1A of this report, which is incorporated herein by reference.

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 12 rigs currently contracted. Our contract backlog attributable to our expected operations offshore Brazil is $1.2 billion, $1.0 billion, $0.5 billion and $62.0 million for the years 2013, 2014, 2015 and 2016, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview – Contract Drilling Backlog” in Item 7 of this report.

Competition

Despite consolidation in recent years, the offshore contract drilling industry remains highly competitive with numerous industry participants, none of which at the present time has a dominant market share. The industry may also experience additional consolidation in the future, which could create other large competitors. Some of our competitors may have greater financial or other resources than we do. We compete with offshore drilling contractors that together have almost 780 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.

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 94%, 90% and 81% of our total consolidated revenues for the years ended December 31, 2012, 2011 and 2010, respectively. See “Risk Factors – Significant portions 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, 2012, we had approximately 5,300 workers, including international crew personnel furnished through independent labor contractors.

Executive Officers of the Registrant

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


Name	Age as of January 31, 2013	Position
Lawrence R. Dickerson	60	President, Chief Executive Officer and Director
John M. Vecchio	62	Executive Vice President
Gary T. Krenek	54	Senior Vice President and Chief Financial Officer
William C. Long	46	Senior Vice President, General Counsel & Secretary
Beth G. Gordon	57	Controller – Chief Accounting Officer
Lyndol L. Dew	58	Senior Vice President – Worldwide Operations
Michael D. Acuff	42	Senior Vice President – Contracts and Marketing

Lawrence R. Dickerson has served as our President and a Director since March 1998 and as our Chief Executive Officer since May 2008. Mr. Dickerson served as our Chief Operating Officer from March 1998 to May 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.

Michael D. Acuff has served as a Senior Vice President since April 2012. Mr. Acuff served as our Vice President – Contracts and Marketing from August 2010 to April 2012. Mr. Acuff previously served in a number of positions for another offshore drilling contractor, Transocean, including as Director of Corporate Planning from November 2009 to August 2010; Director of Marketing, Asia and Pacific Business Unit from July 2009 to November 2009; North America Marketing Manager from April 2008 to July 2009; and People Development Manager, North and South America from May 2007 to April 2008.

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.

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, as of the date of this report, we believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.

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:

•

worldwide demand for oil and gas;

•

the level of economic activity in energy-consuming markets;

•

the worldwide economic environment or economic trends, such as recessions;

•

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

•

the level of production in non-OPEC countries;

•

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

•

civil unrest;

•

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

•

the discovery rate of new oil and gas reserves;

•

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

•

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

•

the ability of oil and gas companies to raise capital;

•

weather conditions;

•

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

•

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

•

development and exploitation of alternative fuels or energy sources;

•

competition for customers’ drilling budgets from land-based energy markets around the world;

•

domestic and foreign tax policy; and

•

advances in exploration and development technology.

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 offshore 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 for additional equipment to comply with existing or new governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or result in a reduction in revenues associated with downtime required to install such equipment, or may otherwise significantly limit drilling activity.

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

Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.

As awareness of climate change issues increases, governments around the world are beginning to adopt laws and regulations to address the matter. Lawmakers and regulators in the United States and other jurisdictions where we operate have focused increasingly on restricting the emission of carbon dioxide, methane and other “greenhouse”

gases that may contribute to warming of the Earth’s atmosphere and other climatic changes. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business, and could adversely affect our operations by limiting drilling opportunities.

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 fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial condition and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that 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, laws and regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations.

Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time they were performed.

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

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

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. 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 67 floaters on order and scheduled for delivery between 2013 and 2016 with approximately 75% of these rigs scheduled for delivery in 2013 and 2014. 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 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 33% of our consolidated revenues in 2012 and, as of February 1, 2013, accounted for approximately $2.6 billion of our contract drilling backlog through 2016 and to which nine of our floaters are currently contracted, has announced plans to construct locally 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling units, if built, 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 or unwillingness to fulfill their contractual commitments to us may have a material adverse effect on our financial condition, results of operations and cash flows. See “– Our industry is highly competitive and cyclical, with intense price competition” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview – Contract Drilling Backlog” in Item 7 of this report.

We 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 2012, our five largest customers in the aggregate accounted for 62% of our consolidated revenues. We expect Petrobras and OGX, which accounted for approximately 33% and 12% of our consolidated revenues in 2012, respectively, to continue to be significant customers in 2013. Our contract drilling backlog, as of the date of this report, includes $1.0 billion, or 36%, and $187.0 million, or 7%, of our total contracted backlog in 2013, which is attributable to contracts with Petrobras and OGX, respectively, for operations offshore Brazil. Petrobras has announced plans to construct locally 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling units, if built, 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. While it is normal for our customer base to change over time as work programs are completed, the loss of, or a significant reduction in the number of rigs contracted with, any major customer may have a material adverse effect on our financial condition, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview – Contract Drilling Backlog” in Item 7 of this report.

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 condition, results of operations and cash flows.

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 condition, 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 economic downturns. 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 condition, results of operations and cash flows.

Significant portions 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:

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war and civil disturbances;

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piracy or assaults on property or personnel;

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kidnapping of personnel;

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expropriation or nationalization of property or equipment;

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renegotiation or nullification of existing contracts;

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changing political conditions;

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imposition of trade barriers or import-export quotas;

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foreign and domestic monetary policies;

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the inability to repatriate income or capital;

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difficulties in collecting accounts receivable and longer collection periods;

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fluctuations in currency exchange rates;

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regulatory or financial requirements to comply with foreign bureaucratic actions;

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travel limitations or operational problems caused by public health threats;

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

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

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changing taxation policies.

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:

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the equipping and operation of drilling units;

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import-export quotas or other trade barriers;

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repatriation of foreign earnings or capital;

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oil and gas exploration and development;

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taxation of offshore earnings and earnings of expatriate personnel; and

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

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.

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.

We may enter into drilling contracts that expose us to greater risks than we normally assume.

From time to time, we may enter into drilling contracts with national oil companies, government-controlled entities or others that expose us to greater risks than we normally assume, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to us, or if a termination payment is required, it may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. 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 tax laws, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results.

Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our worldwide operations through various subsidiaries in a number of 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 us or our operations, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.

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 condition, 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 condition, 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. We may not have insurance for litigation or claims that may arise, or if we do have insurance coverage it may not be sufficient, insurers may not remain solvent or other claims may exhaust some or all of the insurance available to us. 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 four new ultra-deepwater drillships under construction which will require additional skilled personnel to operate. Additional new capacity in the offshore drilling market could also cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. The heightened competition for skilled personnel could materially and adversely impact our financial condition, results of operations and cash flows by limiting our operations and further increasing our costs.

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” in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of this report.

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

From time to time we add new capacity through conversions or upgrades to our existing rigs or through new construction, such as our four ultra-deepwater drillships under construction and construction of the Ocean Apex and 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:

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shortages of equipment, materials or skilled labor;

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work stoppages;

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unscheduled delays in the delivery of ordered materials and equipment;

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unanticipated cost increases;

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weather interferences or storm damage;

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difficulties in obtaining necessary permits or in meeting permit conditions;

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design and engineering problems;

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availability of suppliers to recertify equipment for enhanced regulations;

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customer acceptance delays;

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shipyard failures or unavailability; and

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failure or delay of third party service providers, civil unrest and labor disputes.

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 condition, 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, 2012, we had $1.5 billion in long-term debt maturing at various times from September 2014 through 2039. 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, we may need to refinance our long-term debt on or before maturity, and 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 may incur asset impairments as a result of declining demand for certain types of offshore drilling rigs.

new-build, construction project or major rig upgrade), and we could incur impairment charges related to the carrying value of our drilling rigs. We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment, which reflects management’s assumptions and estimates regarding the appropriate risk-adjusted dayrate by rig, future industry conditions and operations and other factors. Asset impairment evaluations are, by their nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets which could impact the need to record an impairment charge and the amount of any charge taken. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Overview – Critical Accounting Estimates – Property, Plant and Equipment” in Item 7 of this report.

We can provide no assurance that our assumptions and estimates will ultimately be realized, nor can we provide any assurance that the current carrying value of our property and equipment, including rigs designated as held for sale, will ultimately be realized.

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

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

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

Loews Corporation, which we refer to as Loews, beneficially owned approximately 50.4% of our outstanding shares of common stock as of February 18, 2013 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, two 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.

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 55% owned subsidiary engaged in transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation of 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 office building in Houston, Texas, where our corporate headquarters are located. We also own offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil, and Ciudad del Carmen, Mexico. Additionally, we currently lease various office, warehouse and storage facilities in 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.

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

Item 4.

Mine Safety Disclosures.

Not applicable.

PART II

Item 5.

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

Price Range of Common Stock

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


	Common Stock
	High		Low

2012
First Quarter	$	72.43	$	55.61
Second Quarter		69.39		56.18
Third Quarter		69.24		58.85
Fourth Quarter		71.14		64.91
2011
First Quarter	$	78.96	$	64.74
Second Quarter		80.14		66.65
Third Quarter		72.73		54.74
Fourth Quarter		69.25		52.90

As of February 15, 2013 there were approximately 187 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 2012, we paid regular cash dividends of $0.125 and special cash dividends of $0.75 per share of our common stock on March 1, June 1, September 4 and December 3. 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.

On February 4, 2013, 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 quarterly and special cash dividends are payable on March 1, 2013 to stockholders of record on February 19, 2013.

CUMULATIVE TOTAL STOCKHOLDER RETURN

The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index and the Dow Jones U.S. Oil Equipment & Services index over the five year period ended December 31, 2012.

Comparison of 2008 – 2012 Cumulative Total Return (1)

LOGO


	Dec. 31, 2007	Dec. 31, 2008	Dec. 31, 2009	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2012
Diamond Offshore	100	44	81	59	51		66
S&P 500	100	63	80	92	94		109
Dow Jones U.S. Oil Equipment & Services	100	41	66	83	76		77

(1)

Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2007 in our common stock and the two published indices.

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


	Q1				Q2				Q3				Q4
Year	Regular		Special		Regular		Special		Regular		Special		Regular		Special

2012		$ 0.125		$ 0.75		$ 0.125		$ 0.75		$ 0.125		$ 0.75		$ 0.125		$ 0.75
2011		$ 0.125		$ 0.75		$ 0.125		$ 0.75		$ 0.125		$ 0.75		$ 0.125		$ 0.75
2010		$ 0.125		$ 1.875		$ 0.125		$ 1.375		$ 0.125		$ 0.75		$ 0.125		$ 0.75
2009		$ 0.125		$ 1.875		$ 0.125		$ 1.875		$ 0.125		$1.875		$ 0.125		$1.875
2008		$ 0.125		$ 1.25		$ 0.125		$ 1.25		$ 0.125		$1.25		$ 0.125		$1.875

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 annual period ending on December 31, 2008 has 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 period as of and for the year ended December 31, 2008 presented below.


	As of and for the Year Ended December 31,
	2012		2011		2010		2009		2008 Adjusted
	(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues		$2,986,508		$3,322,419		$3,322,974		$3,631,284		$3,544,057
Operating income		962,378		1,255,414		1,425,374		1,903,213		1,910,194
Net income		720,477		962,542		955,457		1,376,219		1,310,547
Net income per share:
Basic		5.18		6.92		6.87		9.90		9.43
Diluted		5.18		6.92		6.87		9.89		9.42

Balance Sheet Data:
Drilling and other property and equipment, net		$4,864,972		$4,667,469		$4,283,792		$4,432,052		$3,414,373
Total assets		7,235,286		6,964,157		6,726,984		6,264,261		4,954,431
Long-term debt (excluding current maturities)		1,496,066		1,495,823		1,495,593		1,495,375		503,280

Other Financial Data:
Capital expenditures		$ 702,041		$ 774,756		$ 434,262		$1,362,468		$ 666,857
Cash dividends declared per share		3.50		3.50		5.25		8.00		6.13
Ratio of earnings to fixed charges (1)		11.11x		14.40x		15.35x		37.29x		64.54x

(1)

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

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 44 offshore drilling rigs, including assets held for sale, consists of 32 semisubmersibles, seven jack-ups and five dynamically positioned drillships, four of which are under construction. We expect two of our new drillships to be delivered in the second and fourth quarters of 2013 and the remaining two to be delivered in the second and fourth quarters of 2014. Our semisubmersible fleet includes the Ocean Onyx and the Ocean Apex, which are currently under construction. We expect the Ocean Onyx and Ocean Apex to be available for drilling service in the third quarter of 2013 and second quarter of 2014, respectively.

During 2012, we sold six of our jack-up rigs, including four rigs that had been cold stacked in previous periods. Currently, three mid-water floaters and one jack-up rig are being marketed for sale.

Market Overview

International Floater Market

Internationally, the ultra-deepwater and deepwater floater markets are generally strong and continue to show signs of further strengthening, particularly in the ultra-deepwater segment where there are reportedly few, if any, uncontracted rigs available to work in 2013, inclusive of the expected 2013 newbuild deliveries. Analyst data at the end of 2012 indicated that this market is expected to remain strong throughout 2013. We believe that the diminished availability of rigs in this market could continue to put upward pressure on dayrates during 2013. However, due to our contracted backlog in 2013 (100% and 92% for our ultra-deepwater and deepwater fleets, respectively), we have limited availability in this market and may not be able to benefit from higher price fixtures during that period. See “– Contract Drilling Backlog.”

Newbuild orders for ultra-deepwater and deepwater floaters continued to be placed in 2012, including our order for a fourth drillship, the Ocean BlackLion, and our deepwater floater, the Ocean Apex, both of which are currently under construction. Based on recent analyst data, there are 67 floater rigs, primarily ultra-deepwater and deepwater units, on order or under construction, excluding an estimated 29 rigs to be built on behalf of Petróleo Brasileiro S.A., or Petrobras, which is currently our most significant customer. Excluding the Petrobras-ordered rigs, nearly 73% of the floaters scheduled for delivery in 2014 and beyond are not yet contracted for future work, including two of our drillships under construction and the Ocean Apex.

In addition, Petrobras has recently announced that it plans to cap the number of its contracted deepwater rigs beginning in 2016. According to industry analysts, they believe Petrobras intends to fill the majority of its deepwater requirement with its own rigs, which are not yet under construction, but which are scheduled for delivery in 2015 and beyond, although industry analysts believe that this timing may be delayed due to current Brazilian shipyard limitations. If imposed by Petrobras, this limit on the number of contracted rigs could lead to additional availability and increased competition in the deepwater market in the future.

Market demand for mid-water floaters is generally stable and is also strengthening in certain geographic markets. In both the United Kingdom, or U.K., and Norway sectors of the North Sea, the mid-water market is very strong with industry analysts predicting the next availability of rigs in late 2013. A 2012 discovery offshore Norway has resulted in increased interest in the harsh North Sea region, where there is a limited number of rigs capable of working and the barriers to entry are high, primarily due to significant rig modifications necessary to operate in the region. In February 2013, we announced our plan to upgrade one of our mid-water floaters, the Ocean Patriot, for North Sea operations, and the execution of a minimum three-year contract for the upgraded rig in the U.K. sector of the North Sea beginning in 2014. In the Mediterranean region, demand remains solid, including the Black Sea region where recent gas discoveries have led to increased interest in the region. The Southeast Asia and Australia markets also remain steady with indications of possible strengthening.

As of the date of this report, industry-wide floater utilization is reported to be approximately 87%, and, as of February 1, 2013, our floating rigs in the aggregate were committed for 83% and 60% of 2013 and 2014, respectively. See “– Contract Drilling Backlog.”

International 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. Our other international jack-up rig commenced a two-year bareboat charter offshore Ecuador in the third quarter of 2012.

GOM Floater and Jack-up Market

Drilling activity on the Outer Continental Shelf of the Gulf of Mexico has continued to strengthen and has surpassed pre-Macondo levels. Additionally, some industry analysts predict that drilling activity, particularly in the ultra-deepwater market, will continue to strengthen in 2013 and beyond. However, our ability to meet this demand is limited in the near term. We currently have two semisubmersibles on contract in the GOM, one of which is expected to have limited availability in the second half of 2013. We also have one mid-water floater and one jack-up rig in the GOM available for contract, having relocated the Ocean Ambassador (in late 2012) and Ocean King (in early 2013) to the GOM. Looking forward, we have two ultra-deepwater drillships under construction, as well as the Ocean Apex, none of which have been contracted, which could be positioned in this market. All three of these rigs are scheduled for delivery in 2014. The Ocean Onyx, which is currently under construction, is expected to commence a one-year contract plus potential option periods in the GOM during the third quarter of 2013.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of February 1, 2013, October 17, 2012 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012) and February 1, 2012 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2011). 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.


	February 1, 2013		October 17, 2012		February 1, 2012
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	4,422,000	$	4,660,000	$	4,926,000
Deepwater⁽²⁾		1,229,000		1,373,000		1,081,000
Mid-Water⁽³⁾		2,649,000		2,510,000		2,348,000

Total Floaters		8,300,000		8,543,000		8,355,000

Jack-ups		272,000		203,000		277,000

Total	$	8,572,000	$	8,746,000	$	8,632,000

(1)

Contract drilling backlog as of February 1, 2013 for our ultra-deepwater floaters includes (i) $1.3 billion attributable to our contracted operations offshore Brazil for the years 2013 to 2015 and (ii) $1.8 billion attributable to future work for two of our drillships under construction for the years 2013 to 2019.

(2)

Contract drilling backlog as of February 1, 2013 for our deepwater floaters includes (i) $563.0 million attributable to our contracted operations offshore Brazil for the years 2013 to 2016 and (ii) $179.0 million for the years 2013 to 2014 attributable to future work for the Ocean Onyx, which is under construction.

(3)

Contract drilling backlog as of February 1, 2013 for our mid-water floaters includes $880.0 million attributable to our contracted operations offshore Brazil for the years 2013 to 2015.

The following table reflects the amount of our contract drilling backlog by year as of February 1, 2013.


	For the Years Ending December 31,

	Total		2013		2014		2015		2016 - 2019

	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	4,422,000	$	979,000	$	1,223,000	$	996,000	$	1,224,000
Deepwater⁽²⁾		1,229,000		569,000		456,000		142,000		62,000
Mid-Water⁽³⁾		2,649,000		1,106,000		955,000		408,000		180,000

Total Floaters		8,300,000		2,654,000		2,634,000		1,546,000		1,466,000

Jack-ups		272,000		140,000		72,000		48,000		12,000

Total	$	8,572,000	$	2,794,000	$	2,706,000	$	1,594,000	$	1,478,000

(1)

Contract drilling backlog as of February 1, 2013 for our ultra-deepwater floaters includes (i) $524.0 million, $473.0 million and $324.0 million for the years 2013 to 2015, respectively, attributable to our contracted operations offshore Brazil and (ii) $29.0 million, $299.0 million and $361.0 million for the years 2013, 2014 and 2015, respectively, and $1.1 billion in the aggregate for the years 2016 to 2019, attributable to future work for two of our drillships under construction.

(2)

Contract drilling backlog as of February 1, 2013 for our deepwater floaters includes (i) $218.0 million, $149.0 million, $134.0 million and $62.0 million for the years 2013 to 2016, respectively, attributable to our contracted operations offshore Brazil and (ii) $45.0 million and $134.0 million for the years 2013 and 2014, respectively, attributable to future work for the Ocean Onyx, which is under construction.

(3)

Contract drilling backlog as of February 1, 2013 for our mid-water floaters includes $456.0 million, $342.0 million and $82.0 million for the years 2013 to 2015, respectively, attributable to our contracted operations offshore Brazil.

The following table reflects the percentage of rig days committed by year as of February 1, 2013. 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 Onyx, Ocean BlackHornet, Ocean Apex, Ocean BlackRhino and Ocean BlackLion, which are all under construction.


	For the Years Ending December 31,
	2013	2014	2015	2016 - 2019
Rig Days Committed ⁽¹⁾
Floaters:
Ultra-Deepwater	100%	86%	57%	14%
Deepwater	92%	44%	15%	2%
Mid-Water	72%	50%	18%	2%
All Floaters	83%	60%	30%	6%
Jack-ups	69%	39%	20%	1%

(1)

As of February 1, 2013, includes approximately 1,540, 660 and 140 currently known, scheduled shipyard, survey and mobilization days for 2013, 2014 and 2015, respectively.

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

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

Revenue is also affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, we may receive fees for the mobilization of equipment. In addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which we may be compensated. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation fees received (either lump-sum or dayrate), as well as direct and incremental costs associated with the mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the term of the related drilling contracts. Absent a contract, mobilization costs are recognized currently.

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

The 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 2013 as a result of increased hiring and training activities as we continue the process of crewing our four 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.

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs, which are recognized as incurred. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.

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

As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, we expect contract drilling revenue in 2013 to decline from the levels attained in 2012. During 2013, 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 830 days in the aggregate. We also expect to spend an additional approximately 590 days during 2013 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects, including contract preparation work for the Ocean Endeavor and North Sea enhancements for the Ocean Patriot, each of which is expected to require approximately 180 days of downtime. 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 “ – Market Overview – Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our insurance policy that expires on May 1, 2013, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our current insurance policy, 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.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use, which is expected to continue after delivery of the rigs from the shipyard and until the user acceptance phase of each project is completed. For the year ended December 31, 2012, we capitalized interest of $37.7 million on qualifying expenditures, primarily related to the construction of our four new drillships and the Ocean Onyx and the Ocean Apex. We will continue capitalizing interest on qualifying expenditures during 2013 and expect the amount of interest capitalized to increase, compared to 2012, as construction of two of the drillships and the Ocean Onyx is scheduled for completion in 2013 and final installments and milestone payments will be made on the associated construction contracts.

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, 2012 and 2011, we capitalized $220.3 million and $269.5 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $60 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 an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

•

dayrate by rig;

•

utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);

•

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

•

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

•

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

•

salvage value for each rig; and

•

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

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.

Similarly, when a rig is reclassified to “Assets held for sale,” we measure the asset at the lower of its carrying amount or fair value less cost to sell. In the absence of a letter of intent or contract for the rig’s sale, we measure the fair value using an expected present value technique that utilizes a probability-weighted cash flow analysis, which includes assumptions for estimated proceeds that may be received on disposition of the rig. During 2012, we recognized an impairment loss of $62.4 million in connection with the transfer of three of our mid-water semisubmersible rigs to “Assets held for sale.” See “ – Results of Operations –Years Ended December 31, 2012, 2011 and 2010 – Overview – 2012 Compared to 2011 – Impairment of Assets” and Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report.

A summary of our cold-stacked rigs evaluated for impairment at December 31, 2012, 2011 and 2010 is as follows:


	December 31,

	2012		2011		2010

	(In millions, except number of rigs)
Mid-Water floaters		--		3		3
Jack-ups		--		5		4

Total		--		8		7


Aggregate net book value	$	--	$	76.5	$	78.0

We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these eight and seven rigs were not subject to impairment at December 31, 2011 and 2010, respectively. There were no cold-stacked rigs at December 31, 2012 that were not being marketed for sale.

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, are currently $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims 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:

•

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

•

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

•

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

•

average, potential frequency and severity of claims; and

•

effect of re-opened claims.

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

•

the severity of personal injuries claimed;

•

significant changes in the volume of personal injury claims;

•

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

•

inconsistent court decisions; and

•

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

Income Taxes. We account for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material 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 $2.0 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.

Results of Operations

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

Key performance indicators by equipment type are listed below.


	Year Ended December 31,
	2012		2011		2010
REVENUE EARNING DAYS ⁽¹⁾
Floaters:
Ultra-Deepwater		2,475		2,387		1,873
Deepwater		1,605		1,718		1,342
Mid-Water		4,639		5,254		5,800
Jack-ups ⁽²⁾		1,753		2,218		3,028

UTILIZATION ⁽³⁾
Floaters:
Ultra-Deepwater		85%		82%		66%
Deepwater		88%		94%		74%
Mid-Water		68%		72%		79%
Jack-ups ⁽⁴⁾		53%		47%		61%

AVERAGE DAILY REVENUE ⁽⁵⁾
Floaters:
Ultra-Deepwater	$	354,900	$	342,900	$	358,400
Deepwater		368,800		416,500		401,900
Mid-Water		263,600		269,600		281,000
Jack-ups		90,200		81,900		87,700

⁽¹⁾

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

⁽²⁾

Revenue earning days for the years ended December 31, 2012, 2011 and 2010 included approximately 87 days, 720 days and 1,167 days, respectively, earned by certain of our jack-up rigs during the respective period prior to being sold in 2012 and 2010.

⁽³⁾

Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).

⁽⁴⁾

Utilization for our jack-up rigs would have been 87%, 59% and 73% for the years ended December 31, 2012, 2011 and 2010, respectively, excluding revenue earning days and total calendar days associated with rigs that we sold in 2012 and 2010.

⁽⁵⁾

Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

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

Years Ended December 31, 2012, 2011 and 2010


	Year Ended December 31,
	2012		2011		2010

	(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater	$	902,793	$	841,565	$	718,426
Deepwater		597,694		733,037		564,315
Mid-Water		1,275,068		1,482,032		1,678,793

Total Floaters		2,775,555		3,056,634		2,961,534
Jack-ups		160,511		197,534		267,983
Other		--		145		219

Total Contract Drilling Revenue	$	2,936,066	$	3,254,313	$	3,229,736



Revenues Related to Reimbursable Expenses	$	50,442	$	68,106	$	93,238

CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater	$	545,590	$	492,816	$	320,358
Deepwater		253,176		227,733		219,685
Mid-Water		602,351		632,755		641,660

Total Floaters		1,401,117		1,353,304		1,181,703
Jack-ups		106,510		169,229		190,167
Other		29,597		25,969		19,216

Total Contract Drilling Expense	$	1,537,224	$	1,548,502	$	1,391,086



Reimbursable Expenses	$	48,778	$	66,052	$	91,240

OPERATING INCOME
Floaters:
Ultra-Deepwater	$	357,203	$	348,749	$	398,068
Deepwater		344,518		505,304		344,630
Mid-Water		672,717		849,277		1,037,133

Total Floaters		1,374,438		1,703,330		1,779,831
Jack-ups		54,001		28,305		77,816
Other		(29,597)		(25,824)		(18,997)
Reimbursable expenses, net		1,664		2,054		1,998
Depreciation		(392,913)		(398,612)		(393,177)
Impairment of assets		(62,437)		--		--
General and administrative expense		(64,640)		(65,310)		(66,600)
Bad debt recovery		1,018		6,713		9,789
Gain on disposition of assets		80,844		4,758		34,714

Total Operating Income	$	962,378	$	1,255,414	$	1,425,374



Other income (expense):
Interest income		4,910		6,668		2,909
Interest expense		(46,216)		(73,137)		(90,698)
Foreign currency transaction gain (loss)		(1,999)		(8,588)		1,369
Other, net		(992)		(1,086)		(2,938)

Income before income tax expense		918,081		1,179,271		1,336,016
Income tax expense		(197,604)		(216,729)		(380,559)

NET INCOME	$	720,477	$	962,542	$	955,457

The following is a summary of the most significant transfers of our rigs during 2010, 2011 and 2012 between the geographic areas in which we operate:


Rig	Rig Type	Relocation Details	Date
*Floaters:*
Ocean Baroness	Ultra-Deepwater	GOM to Brazil	March 2010
Ocean Courage	Ultra-Deepwater	GOM to Brazil	March 2010
Ocean Valor	Ultra-Deepwater	Rig placed in service. Singapore shipyard to Brazil	March 2010
Ocean Endeavor	Ultra-Deepwater	GOM to Egypt	August 2010
Ocean Confidence	Ultra-Deepwater	GOM to the Republic of Congo	August 2010
Ocean Monarch	Ultra-Deepwater	GOM to Vietnam	September 2011
Ocean Monarch	Ultra-Deepwater	Vietnam to Singapore (shipyard survey)	August 2012

Ocean Star	Deepwater	GOM to Brazil	January 2010
Ocean America	Deepwater	GOM to Australia	March 2010

Ocean Onyx	Mid-Water	Mexico to GOM ^(a)	March 2010
Ocean New Era	Mid-Water	Mexico to GOM (cold stacked September 2010)^(b)	August 2010
Ocean Epoch	Mid-Water	Malaysia (cold stacked) ^(b)	February 2011
Ocean Yorktown	Mid-Water	Brazil to GOM	August 2011
Ocean Yorktown	Mid-Water	GOM to Mexico	December 2011
Ocean Guardian	Mid-Water	Falkland Islands to U.K.	January 2012
Ocean Saratoga	Mid-Water	GOM to Guyana	January 2012
Ocean Saratoga	Mid-Water	Guyana to GOM	May 2012
Ocean Whittington	Mid-Water	Brazil to GOM ^(b)	May 2012
Ocean Apex	Mid-Water	Singapore shipyard ^{(c )}	September 2012
Ocean Ambassador	Mid-Water	Brazil to GOM	October 2012

*Jack-ups:*
Ocean Shield	Jack-up	Sold	July 2010
Ocean Scepter	Jack-up	GOM to Brazil	August 2010
Ocean Spartan	Jack-up	GOM (cold stacked) ^(b)	September 2010
Ocean Scepter	Jack-up	Brazil to GOM	October 2011
Ocean Titan	Jack-up	GOM to Mexico	November 2011
Ocean Scepter	Jack-up	GOM to Mexico	December 2011
Ocean Columbia	Jack-up	Sold	March 2012
Ocean Heritage	Jack-up	Sold	April 2012
Ocean Drake	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Champion	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Crusader	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Sovereign	Jack-up	Sold (cold stacked October 2011)	June 2012
Ocean Spur	Jack-up	Egypt to Ecuador; two year bareboat charter	August 2012
Ocean King	Jack-up	Montenegro to GOM (in transit)	December 2012

(a)

Rig formerly operated as the Ocean Voyager and was cold stacked in June 2010. Rig has been used in the construction of a deepwater floater in Brownsville, Texas.

(b)

Rig held for sale at December 31, 2012.

(c)

Rig formerly operated as the Ocean Bounty and was cold stacked in July 2009. Rig has been used in the construction of a deepwater floater in Singapore.

Overview

2012 Compared to 2011

Operating Income. Operating income decreased $293.0 million, or 23%, during 2012, compared to 2011, primarily due to a $318.2 million, or 10%, reduction in total contract drilling revenue and a $62.4 million impairment loss on certain assets held for sale, partially offset by an $11.3 million, or 1%, decrease in contract drilling expense and a $76.5 million pre-tax gain on the sale of six jack-up rigs in 2012. Both revenue earning days and average daily

revenue earned by our deepwater and mid-water floaters declined during 2012, compared to 2011, resulting in a $342.3 million reduction in revenue, while continued favorable market conditions for our ultra deepwater floaters resulted in a $61.2 million increase in contract drilling revenue. Revenue for our jack-up fleet decreased $37.0 million during 2012, compared to 2011, primarily due to the 2012 sale of three jack-up rigs that operated during 2011.

Aggregate contract drilling expense for our mid-water floater and jack-up fleets decreased $93.1 million during 2012 compared to the prior year, primarily due to the movement of certain of our rigs to other operating regions with lower cost structures, combined with lower repair and inspection costs, as well as the absence of operating costs in 2012 for the recently sold jack-up rigs. The overall decrease in contract drilling expense during 2012 was partially offset by a combined $78.2 million increase in contract drilling expense for our ultra-deepwater and deepwater floaters, primarily due to higher personnel related, inspection, and shorebase support costs in 2012.

Impairment of Assets. In late 2012, our management adopted a plan to actively market for sale three of our mid-water semisubmersibles, consisting of two previously cold-stacked rigs (the Ocean Epoch and Ocean New Era) and the Ocean Whittington, which was idled in 2012 upon its return from Brazil prior to being cold stacked, and the Ocean Spartan, a previously cold-stacked jack-up rig. As a result of this decision, we recognized an impairment loss of $62.4 million in the fourth quarter of 2012 to write down the aggregate net book value of these rigs to their estimated recoverable amounts, aggregating $11.6 million.

Interest Expense. Interest expense decreased $26.9 million in 2012 compared to 2011, primarily due to $26.5 million in incremental interest costs capitalized during 2012 related to our continuing rig construction projects, which now include construction of a fourth drillship and the Ocean Apex.

Income Tax Expense Our effective tax rate for 2012 was 21.5%, compared to an 18.4% effective tax rate for 2011. The higher effective tax rate in 2012 was primarily the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate and the impact of a tax law provision that expired at the end of 2011. This provision allowed us to defer recognition of certain foreign earnings for U.S. tax purposes during 2011, which deferral was unavailable in 2012. Our 2011 tax expense also included the reversal of $15 million of U.S. income tax expense, originally recognized in 2010, related to our intention at that time to repatriate certain foreign earnings, which changed in 2011 subsequent to our decision to build new drillships overseas.

The American Taxpayer Relief Act of 2012, or the Act, was signed into law on January 2, 2013. The Act extends through 2013 several expired or expiring temporary business provisions, commonly referred to as “extenders,” which are retroactively extended to the beginning of 2012. One of the extenders will again allow us to defer recognition of certain foreign earnings for U.S. tax purposes. As required by GAAP, the effects of new legislation are recognized when signed into law. Consequently, we expect to reduce our first quarter 2013 tax expense by approximately $28 million as a result of recognizing the 2012 effect of the extenders.

As our rigs frequently operate in different tax jurisdictions as they move from contract to contract, our effective tax rate can fluctuate substantially and our historical effective tax rates may not be sustainable and could increase materially.

2011 Compared to 2010

Operating Income. Total operating income in 2011 decreased $170.0 million, or 12%, compared to 2010, despite a $24.6 million, or 1%, increase in total contract drilling revenue during 2011. Revenue generated by our floater rigs increased an aggregate $95.1 million, or 3%, in 2011 compared to 2010, while revenue generated by our jack-up fleet declined $70.4 million or 26%. Except for our deepwater floaters, average daily revenue earned by our other rigs during 2011 compared unfavorably to the levels attained in 2010. Utilization for our ultra-deepwater and deepwater floaters increased significantly in 2011 compared to 2010; however, utilization for our mid-water floater and jack-ups fleets decreased in 2011. One additional mid-water floater and one jack-up rig were cold stacked during 2011. The Ocean Courage and Ocean Valor, which began operating under contract late in the first quarter and in the fourth quarter of 2010, respectively, contributed incremental revenue of $162.0 million during 2011.

Total contract drilling expense increased $157.4 million, or 11%, during 2011 compared to 2010, and reflected incremental contract drilling expense for the Ocean Courage and Ocean Valor, higher amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.

Other significant factors that affected the comparability of our operating income for the years ended December 31, 2011 and 2010 were as follows:

•

Bad Debt Recovery (Expense). During 2011, we recorded a $5.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $12.3 million in previously recorded reserves for bad debts. During 2010, we recovered $5.6 million and $4.2 million related to previously established reserves for bad debts related to our operations in Egypt and the U.K., respectively.

•

Gain on Disposition of Assets. During 2011, we recognized an aggregate $4.8 million gain on the disposition of assets, primarily related to the sale of used equipment, compared to an aggregate $34.7 million net gain recognized in the prior year. During 2010, we sold the Ocean Shield for net proceeds of $183.3 million and recognized a net gain on sale of $32.8 million.

Interest Expense. Interest expense decreased $17.6 million in 2011 compared to 2010, primarily due to $11.2 million of interest capitalized in 2011 on our three drillships under construction at that time. In addition, during 2011, we recorded $0.2 million of interest expense related to uncertain tax positions compared to $4.8 million during 2010.

Income Tax Expense. Our effective tax rate for 2011 was 18.4%, compared to a 28.5% effective tax rate for 2010. The lower effective tax rate in 2011 was primarily the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate.

A tax law provision that expired at the end of 2009 but was subsequently signed back into law in December 2010 also contributed to our lower effective tax rate in 2011. This provision allowed us to defer recognition of certain foreign earnings for U.S. tax purposes. The extension of this tax law provision, and our decisions to build three new drillships overseas, caused us to reassess our intent to repatriate certain foreign earnings to the U.S. We plan to reinvest these earnings internationally, and consequently, we no longer provide U.S. income taxes on these earnings. During the year ended December 31, 2011, we reversed the $15.0 million of U.S. income taxes that had been provided in 2010 for these earnings.

On December 31, 2011, the statute of limitations relative to a 2006 uncertain tax position in Brazil expired. As a consequence, in 2011 we reversed $1.1 million of previously accrued interest expense and $5.7 million of previously accrued tax expense, $2.0 million of which had been accrued for penalties. During 2010, we accrued approximately $35.7 million of expense for uncertain tax positions, primarily in Mexico and Brazil, of which $4.8 million was interest and $12.0 million was penalty related.

Contract Drilling Revenue and Expense by Equipment Type

2012 Compared to 2011

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $61.2 million during 2012, compared to 2011, primarily due to higher average daily revenue earned by our ultra-deepwater fleet ($29.9 million) and 88 incremental revenue earning days ($30.4 million). Average daily revenue earned increased primarily due to higher dayrates earned by the Ocean Monarch operating offshore Vietnam and Indonesia during 2012, compared to the average dayrate earned by the rig operating in the GOM during 2011. Total revenue earning days increased during 2012 primarily due to the inclusion of 155 incremental revenue earnings days for the Ocean Monarch, compared to 2011 when the rig incurred downtime associated with a force majeure assertion by a customer that was ultimately settled in April 2011 and mobilization of the rig to Vietnam. The increase in aggregate revenue earning days during 2012 was partially offset by downtime associated with scheduled surveys and shipyard projects, as well as unscheduled downtime for repairs for other rigs in our ultra-deepwater fleet.

Contract drilling expense in 2012 for our ultra-deepwater fleet included $26.3 million in incremental costs for the Ocean Monarch, which experienced a higher cost structure operating internationally for the full year, as well as costs associated with its 2012 shipyard survey, compared to 2011, when the rig was located in the GOM for a portion of the year. In addition, contract drilling expense for our other ultra-deepwater floaters increased compared to 2011, reflecting higher costs relating to personnel ($28.8 million), inspections ($3.9 million), freight, customs and duties ($3.3 million) and shorebase support ($5.5 million), as well as losses on foreign currency hedges ($3.8

million), partially offset by lower costs incurred for maintenance and repairs ($13.0 million) and amortized mobilization expense ($7.5 million). Many of these costs are difficult to predict by their nature and vary based on the local laws and practices in the international locations in which our ultra-deepwater floaters operate.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $135.3 million in 2012, compared to 2011, as a result of lower average daily revenue earned ($76.5 million), 113 fewer revenue earning days ($47.2 million), and lower recognition of amortized mobilization revenue ($11.7 million). Average daily revenue earned was negatively impacted by the completion of the Ocean Valiant’s initial contract offshore Angola in December 2011, which was at a significantly higher dayrate than the rig earned during 2012. The decline in revenue earning days during 2012 was primarily attributable to 118 days of incremental downtime for shipyard projects and inspections compared to 2011. Contract drilling expense incurred by our deepwater floaters increased $25.4 million during 2012, compared to 2011, primarily due to the repair and inspection costs associated with 2012 surveys and shipyard projects for the Ocean Star and Ocean Victory and higher personnel related costs, partially offset by the absence of certain regional costs associated with the Ocean Valiant’s contract offshore Angola during 2011.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $207.0 million during 2012, compared to 2011, primarily due to 615 fewer revenue earning days ($166.0 million). The reduction in revenue earning days in 2012, compared to 2011, reflects 322 incremental downtime days for the Ocean Whittington, which completed its contract in Brazil and is now marketed for sale, as well as unplanned downtime for repairs and the warm stacking of rigs between contracts (163 additional days), planned downtime for mobilization of rigs and shipyard projects (51 additional days), and 91 additional cold-stacked days for the Ocean Epoch. Revenue for 2012, compared to the prior year, was further reduced by a decrease in average daily revenue earned ($27.9 million) and lower amortized mobilization revenue ($13.0 million).

Contract drilling expense for our fleet of eighteen mid-water floaters decreased $30.4 million during 2012 compared to 2011. Significant events or changes that affected the comparability in contract drilling expense between 2012 and 2011 were the relocation of rigs between geographic locations and any related changes in operating cost structures or the cost to mobilize such rigs, the number and extent of shipyard surveys, the stacking of rigs and rising labor costs in the North Sea region, primarily in Norway. In the aggregate, contract drilling expense for 2012, compared to 2011, reflected lower costs for rig maintenance, repairs and inspections ($21.7 million), personnel related ($12.8 million), freight, customs and duties ($5.7 million), revenue-based agency fees ($2.9 million), and shorebase support ($2.2 million), partially offset by higher recognized mobilization costs ($10.0 million) and losses on foreign currency hedges ($7.2 million).

Jack-ups. Revenue and contract drilling expense for our jack-up rigs decreased $37.0 million and $62.7 million, respectively, in 2012, compared to 2011, primarily due to the sale of six jack-up rigs in 2012, which resulted in an incremental reduction of revenue and contract drilling expense of $37.8 million and $37.5 million, respectively, comparing the two years. The decrease in contract drilling expense, compared to 2011, also reflected a $22.0 million reduction in expense for the Ocean Scepter, primarily due to the absence of costs associated with return of the rig to the GOM in 2011, lower amortized mobilization expenses and the effect of a lower operating cost structure offshore Mexico than in Brazil.

2011 Compared to 2010

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $123.1 million during 2011 compared to 2010. The Ocean Courage and Ocean Valor, which began operating under dayrate contracts in February 2010 and October 2010, respectively, were under contract in Brazil for all of 2011 and worked a combined 353 incremental revenue earning days that generated $162.0 million in incremental revenue. However, aggregate revenue earned by our six other ultra-deepwater rigs decreased $38.9 million in 2011, compared to 2010, due to a reduction in average daily revenue earned ($71.5 million), partially offset by an increase in revenue earning days ($57.2 million) due to the absence of downtime in 2011 associated with the relocation of the Ocean Endeavor, Ocean Confidence and Ocean Baroness from the GOM to international locations in the previous year. In addition, 2011 revenue was unfavorably impacted by the absence of a $30.7 million contract termination fee earned by the Ocean Endeavor in July 2010, partially offset by higher recognition of mobilization revenue during 2011 ($6.1 million). Contract drilling expense for our ultra-deepwater floaters increased $172.5 million in 2011, compared to 2010, and included $75.4 million in incremental contract drilling expense from the operation of the Ocean Courage and Ocean Valor, $16.6 million in incremental mobilization expenses, and higher overall contract drilling expenses for the remainder of our fleet, including personnel related, maintenance and hull insurance costs, as well as higher costs associated with operating rigs internationally, such as freight, non-income based taxes, revenue-based agency fees and shorebase support costs.

Deepwater Floaters. Revenue generated by our deepwater floaters increased $168.7 million in 2011, compared to 2010, primarily due to 376 additional revenue earning days ($151.5 million) and an increase in average daily revenue earned ($25.1 million). The increase in revenue earning days in 2011 resulted from 209 fewer non-operating days for repairs, inspections and contract preparation activities, 87 fewer rig mobilization days and 80 fewer days in which rigs were warm stacked between contracts, compared to the prior year. The increase in revenue was partially offset by the recognition of less amortized mobilization revenue in 2011 compared to 2010 ($7.8 million). Contract drilling expense increased $8.0 million in 2011, compared to 2010, primarily due to the Ocean America operating offshore Australia for all of 2011, compared to 2010 when the rig did not commence drilling operations until June 2010 ($27.3 million). Higher incremental contract drilling expense was partially offset by a $16.1 million reduction in recognized mobilization costs due to the full amortization of previously deferred costs as rigs completed their initial contracts and the absence of mobilization costs associated with the Ocean Alliance’s shipyard project in 2010.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $196.8 million in 2011, compared to 2010, primarily due to 546 fewer revenue earning days ($153.4 million) combined with a decrease in average daily revenue earned ($59.3 million) in 2011. The decrease in revenue earning days was primarily attributable to 963 additional cold-stacked days in 2011 compared to 2010, partially offset by fewer warm-stacked days between contracts (282 fewer days), unpaid downtime for repairs (84 fewer days) and rig mobilization days (51 fewer days). The decline in revenue was partially offset by higher mobilization fees recognized during 2011 ($15.9 million), compared to 2010, primarily due to a $24.0 million demobilization fee earned by the Ocean Yorktown upon completion of its contract offshore Brazil. Contract drilling expense decreased $8.9 million during 2011 compared to 2010. Contributing to the overall decrease in contract drilling expense between periods was a $67.6 million reduction in costs associated with cold-stacked rigs, partially offset by higher contract drilling expense for our actively-marketed fleet of 16 mid-water floaters. Cost increases in 2011, compared to 2010, included personnel-related costs ($21.7 million), repairs and maintenance expenses ($4.3 million), shorebase support and overhead costs ($16.7 million), as well as costs associated with the demobilization of the Ocean Yorktown to the GOM in advance of the rig’s future work in Mexico in early 2012.

Jack-ups. Revenue earned by our jack-up rigs decreased $70.4 million in 2011, compared to 2010, primarily due to 810 fewer revenue earning days ($71.0 million) in 2011, and reflected the impact of rigs cold stacked during the periods (331 fewer days), the sale of the Ocean Shield in July 2010 (232 fewer days) and an increase in warm stacked days between contracts (319 days), partially offset by 72 fewer non-revenue earning days for repairs and mobilization of rigs. Contract drilling expense declined $20.9 million in 2011, compared to 2010, primarily due to reduced expense for our cold-stacked rigs ($9.5 million) and the Ocean Shield ($19.4 million). Contract drilling expense for our actively marketed jack-up rigs increased $8.0 million during 2011, primarily due to higher rig mobilization costs, including costs related to the mobilization of the Ocean Scepter to the GOM, inspection costs and hull insurance.

Liquidity and Capital Resources

We have historically relied principally on our cash flows from operations and cash reserves to meet liquidity needs and fund our cash requirements. In addition, we currently have available a $750 million credit facility to meet our short-term and long-term liquidity needs. See “ – Credit Agreement and Long-Term Debt – $750 Million Revolving Credit Agreement.” At the date of this report, our contract drilling backlog was $8.6 billion, of which $2.8 billion is expected to be earned in 2013.

At December 31, 2012, 2011 and 2010, we had cash available for current operations as follows:


	December 31,

	2012		2011		2010

	(In thousands)
Cash and equivalents	$	335,432	$	333,765	$	464,393
Marketable securities		1,150,158		902,414		612,346

Total cash available for current operations	$	1,485,590	$	1,236,179	$	1,076,739

A substantial portion of our cash flows has been and is expected to continue to be invested in the enhancement of our drilling fleet. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs.

We pay dividends at the discretion of our Board of Directors, or Board, and, in recent years, we have a history of paying both regular quarterly and special cash dividends. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities – Dividend Policy” in Item 5 of this report. During the three-year period ended December 31, 2012, we paid regular cash dividends totaling $208.5 million and special cash dividends totaling $1.5 billion. Our Board has adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Our Board may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined. 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 considers relevant at that time.

Certain of our international rigs are owned and operated, directly or indirectly, by DOIL, and, as a result of our intention to indefinitely reinvest the earnings of DOIL to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. See “ – Market Overview – Critical Accounting Estimates – Income Taxes.” However, we believe that the operating cash flows generated by and cash reserves of DOIL and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. will be sufficient to meet their respective working capital requirements and capital commitments over the next twelve months. We will, however, continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.

During the three-year period ended December 31, 2012, our primary source of cash was an aggregate $4.0 billion generated from operating activities and $317.2 million of proceeds from the sale of seven drilling rigs, including the sale of the Ocean Shield in 2010. Our primary uses of cash during the same period were $1.9 billion towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program and $1.7 billion for the payment of dividends.

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

Cash Flow and Capital Expenditures

Our cash flow from operations and capital expenditures for each of the years in the three-year period ended December 31, 2012 were as follows:


	Year Ended December 31,

	2012		2011		2010

	(In thousands)
Cash flow from operations	$	1,311,269	$	1,420,105	$	1,282,318

Capital expenditures:
Drillship construction	$	248,346	$	490,156	$	--
Construction of deepwater floaters		153,529		--		--
Ongoing rig equipment and replacements programs		300,166		284,600		434,262

Total capital expenditures	$	702,041	$	774,756	$	434,262

Cash Flow. Cash flow from operations decreased approximately $108.8 million during 2012, compared to 2011, primarily due to a $297.4 million decrease in cash receipts from contract drilling services, partially offset by lower cash payments related to contract drilling expenses of $87.3 million and lower cash income taxes paid, net of refunds, of $102.0 million.

Cash flow from operations increased approximately $137.8 million during 2011, compared to 2010, primarily due to a reduction in cash income taxes paid, net of refunds, of $310.5 million. However, this reduction in cash outflows from operations was partially offset by a $126.9 million decrease in cash receipts from contract drilling services and higher cash payments related to contract drilling expenses of $46.7 million.

Capital Expenditures.

Drillship Construction. We are financially obligated under four separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of four ultra-deepwater drillships, including one contract which we entered into in May 2012. Two of our drillships are scheduled for delivery in the second and fourth quarters of 2013, with the remaining two drillships scheduled to be delivered in the second and fourth quarters of 2014. The aggregate cost of the four drillships, including commissioning, spares and project management costs, is expected to be approximately $2.6 billion.

The contracted price of each drillship is payable to Hyundai in two installments, with final payment due on delivery of each drillship. We have paid the first installment for each of the four drillships, totaling an aggregate $169.3 million and $478.3 million in 2012 and 2011, respectively. Project-to-date expenditures for our four drillships aggregated $738.5 million at December 31, 2012, inclusive of capitalized interest and the construction installments paid to Hyundai.

Ocean Onyx Construction. We are obligated under a vessel modification agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of the Ocean Onyx. The rig is under construction in Brownsville, Texas and is expected to be delivered in the third quarter of 2013. We estimate the aggregate cost for the construction of the Ocean Onyx to be approximately $310.0 million, including commissioning, spares and project management costs. The contracted price due to Keppel is payable in 11 installments based on the occurrence of certain events as detailed in the vessel modification agreement. We paid the first five installments, aggregating $65.7 million, during 2012. Project-to-date expenditures for the Ocean Onyx aggregated $121.3 million at December 31, 2012, inclusive of capitalized interest and construction installments paid to Keppel.

Ocean Apex Construction. In August 2012, we entered into a vessel modification agreement with Jurong Shipyard Pte Ltd, or Jurong, for the construction of the Ocean Apex, a moored semisubmersible rig capable of operating in water depths up to 6,000 feet. The rig is under construction in Singapore and is expected to be delivered in the second quarter of 2014 at an aggregate cost of approximately $370 million, including commissioning, spares and project management costs. The contracted price due to Jurong is payable in 12 installments based on the occurrence of certain events as detailed in the vessel modification agreement. We paid the first two installments, aggregating $27.0 million, during 2012. Project-to-date expenditures for the Ocean Apex aggregated $32.2 million at December 31, 2012, inclusive of capitalized interest and construction installments paid to Jurong.

At the time of this report, we expect capital expenditures for 2013 to aggregate approximately $1.75 billion, of which approximately $1.3 billion will be spent towards the construction projects discussed above. Also included in the 2013 capital spending budget is approximately $120 million estimated to be spent towards the recently announced North Sea enhancement project for the Ocean Patriot. We expect to fund our 2013 capital spending from the operating cash flows generated by and cash reserves of DOIL and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc.

Credit Agreement and Long-Term Debt

$750 Million Revolving Credit Agreement. On September 28, 2012, we entered into a syndicated 5-Year Revolving Credit Agreement, or Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent and swingline lender. The Credit Agreement provides for a $750 million senior unsecured revolving credit facility, for general corporate purposes, maturing on September 28, 2017. The entire amount of the facility is available for revolving loans. Up to $250 million of the facility is available for the issuance of performance or other standby letters of credit and up to $75 million is available for swingline loans. As of December 31, 2012, there were no loans or letters of credit outstanding under the Credit Agreement. See Note 9 “Credit Agreement and Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.

Long-term Debt.

Our long-term debt is comprised as follows:


Name of Issue	Aggregate Principal Amount (In millions)	Maturity Date	Stated Interest Rate	Semiannual Interest Payment Dates
5.15% Senior Notes	$250.0	September 1, 2014	5.15%	March 1 and September 1
4.875% Senior Notes	$250.0	July 1, 2015	4.875%	January 1 and July 1
5.875% Senior Notes	$500.0	May 1, 2019	5.875%	May 1 and November 1
5.70% Senior Notes	$500.0	October 15, 2039	5.70%	April 15 and October 15

See Note 9 “Credit Agreement and Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.

Credit Ratings. Our current credit rating is A3 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings could result in higher interest rates on future debt issuances.

Contractual Cash Obligations ^{(1) (2)}

The following table sets forth our contractual cash obligations at December 31, 2012.


	Payments Due By Period

Contractual Obligations	Total		Less than 1 year		1 – 3 years		4 – 5 years		After 5 years

	(In thousands)
Long-term debt (principal and interest)	$	2,522,752	$	82,938	$	653,001	$	115,750	$	1,671,063
Construction contracts		1,765,800		928,024		837,776		--		--
Operating leases		4,278		2,454		1,816		8		--

Total obligations	$	4,292,830	$	1,013,416	$	1,492,593	$	115,758	$	1,671,063

(1)

The above table excludes foreign currency forward exchange, or FOREX, contracts in the aggregate notional amount of $144.2 million outstanding at December 31, 2012. See further information regarding these contracts in “Quantitative and Qualitative Disclosures About Market Risk – Foreign Exchange Risk” in Item 7A of this report and Note 6 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 8 of this report.

(2)

The above table excludes $48.4 million of unrecognized tax benefits related to uncertain tax positions as of December 31, 2012 and an additional $21.7 million and $7.0 million for potential penalties and interest, respectively, related to such uncertain tax positions. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

Except for the construction contracts discussed above and referred to in the preceding table, we had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2012, except for those related to our direct rig operations, which arise during the normal course of business.

Other Commercial Commitments - Letters of Credit

We were contingently liable as of December 31, 2012 in the amount of $126.5 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $111.5 million of performance and tax appeal bonds can require collateral at any time. As of December 31, 2012, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.


			For the Years Ending December 31,

	Total		2013		2014		Thereafter

	(In thousands)
Other Commercial Commitments
Customs bonds	$	1,444	$	1,444	$	--	$	--
Performance bonds		66,117		20,570		18,986		26,561
Other		58,961		58,961		--		--

Total obligations	$	126,522	$	80,975	$	18,986	$	26,561

Off-Balance Sheet Arrangements

At December 31, 2012 and 2011, we had no off-balance sheet debt or other arrangements.

Other

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

To the extent that we are not able to cover our local currency operating costs with customer payments in the local currency, we also utilize FOREX contracts to reduce our currency exchange risk. Our FOREX contracts may obligate us to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.

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

Forward-Looking Statements

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

•

future market conditions and the effect of such conditions on our future results of operations;

•

future uses of and requirements for financial resources;

•

interest rate and foreign exchange risk;

•

future contractual obligations;

•

future operations outside the United States including, without limitation, our operations in Mexico, Egypt and Brazil;

•

effects of the Macondo well blowout, including, without limitation, the impact of the moratorium and its aftermath on drilling in the U.S. Gulf of Mexico, related delays in permitting activities and related regulations and market developments;

•

business strategy;

•

growth opportunities;

•

competitive position;

•

expected financial position;

•

future cash flows and contract backlog;

•

future regular or special dividends;

•

financing plans;

•

market outlook;

•

tax planning;

•

debt levels, including impacts of the financial crisis and restrictions in the credit market;

•

budgets for capital and other expenditures;

•

timing and duration of required regulatory inspections for our drilling rigs;

•

timing and cost of completion of rig upgrades, construction projects (including, without limitation, our four drillships under construction, the Ocean Onyx and the Ocean Apex) and other capital projects;

•

delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects or rig acquisitions;

•

plans and objectives of management;

•

idling drilling rigs or reactivating stacked rigs;

•

asset impairment evaluations;

•

performance of contracts;

•

outcomes of legal proceedings;

•

compliance with applicable laws; and

•

availability, limits and adequacy of insurance or indemnification.

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

•

those described under “Risk Factors” in Item 1A;

•

general economic and business conditions, including the extent and duration of the recent financial crisis and restrictions in the credit market, the worldwide economic downturn and recession;

•

worldwide demand for oil and natural gas;

•

changes in foreign and domestic oil and gas exploration, development and production activity;

•

oil and natural gas price fluctuations and related market expectations;

•

the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing, and the level of production in non-OPEC countries;

•

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

•

our inability to obtain contracts for our rigs that do not have contracts;

•

the cancellation of contracts included in our reported contract backlog;

•

advances in exploration and development technology;

•

the worldwide political and military environment, including in oil-producing regions;

•

casualty losses;

•

operating hazards inherent in drilling for oil and gas offshore;

•

the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;

•

industry fleet capacity, including construction of new drilling rig capacity in Brazil;

•

market conditions in the offshore contract drilling industry, including dayrates and utilization levels;

•

competition;

•

changes in foreign, political, social and economic conditions;

•

risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;

•

risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;

•

the ability of customers and suppliers to meet their obligations to us and our subsidiaries;

•

the risk that a letter of intent may not result in a definitive agreement;

•

foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;

•

risks of war, military operations, other armed hostilities, terrorist acts and embargoes;

•

changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;

•

regulatory initiatives and compliance with governmental regulations including, without limitation, regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use;

•

compliance with environmental laws and regulations;

•

potential changes in accounting policies by the Financial Accounting Standards Board, the Securities and Exchange Commission, or SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance;

•

development and exploitation of alternative fuels;

•

customer preferences;

•

effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts;

•

cost, availability, limits and adequacy of insurance;

•

invalidity of assumptions used in the design of our controls and procedures;

•

the results of financing efforts;

•

the risk that future regular or special dividends may not be declared;

•

adequacy of our sources of liquidity;

•

risks resulting from our indebtedness;

•

public health threats;

•

negative publicity;

•

impairments of assets;

•

the availability of qualified personnel to operate and service our drilling rigs; and

•

various other matters, many of which are beyond our control.

The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

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

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2012 and 2011, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

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

Interest Rate Risk

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

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on December 31, 2012 and 2011, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

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

Our long-term debt, as of December 31, 2012 and 2011, is denominated in U.S. dollars. Our existing debt has been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $131.4 million and $122.0 million as of December 31, 2012 and 2011, respectively. A 100-basis point decrease would result in an increase in market value of $151.1 million and $142.4 million as of December 31, 2012 and 2011, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into FOREX contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for most of our contracts is the average spot rate for the contract period. As of December 31, 2012, we had FOREX contracts outstanding in the aggregate notional amount of $144.2 million, consisting of $12.2 million in Australian dollars, $72.9 million in Brazilian reais, $42.2 million in British pounds sterling and $16.9 million in Mexican pesos. These contracts generally settle monthly through September 2013. At December 31, 2012, we have presented the fair value of our outstanding FOREX contracts as a current asset of $3.6 million in “Prepaid expenses and other current assets” and a current liability of $(29,137) in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report. We have presented the fair value of our outstanding FOREX contracts at December 31, 2011 as a current asset of $1.3 million in “Prepaid expenses and other current assets” and a current liability of $(8.5) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report.

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

Fair Value Asset (Liability)

Market Risk

December 31,

2012

2011

2012

2011

(In thousands)

Interest rate:

Marketable securities

1,150,200 (a)

902,400 (a)

(2,200) (b)

(4,100) (b)

Foreign Exchange:

Forward exchange contracts –

receivable positions

3,600 (c)

1,300 (c)

(21,600) (d)

(11,400) (d)

Forward exchange contracts –

liability positions

(29) (c)

(8,500) (c)

(4,900) (d)

(14,700) (d)

(a)

The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on December 31, 2012 and 2011.

(b)

The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at December 31, 2012 and 2011.

(c)

The fair value of our foreign currency forward exchange contracts is based on both quoted market prices and valuations derived from pricing models on December 31, 2012 and 2011.

(d)

The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at December 31, 2012 and 2011, with all other variables held constant.

Item 8.

Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Diamond Offshore Drilling, Inc. and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Diamond Offshore Drilling, Inc. and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

February 21, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Diamond Offshore Drilling, Inc. and Subsidiaries

Houston, Texas

We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 21, 2013 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Houston, Texas

February 21, 2013

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)


		December 31,
		2012			2011

ASSETS
Current assets:

Cash and cash equivalents	$		335,432	$		333,765
Marketable securities			1,150,158			902,414
Accounts receivable, net of allowance for bad debts			499,660			563,934
Prepaid expenses and other current assets			136,099			192,570
Assets held for sale			11,594			-

Total current assets			2,132,943			1,992,683
Drilling and other property and equipment, net of accumulated depreciation			4,864,972			4,667,469
Other assets			237,371			304,005

Total assets	$		7,235,286	$		6,964,157


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$		96,631	$		64,147
Accrued liabilities			324,434			336,400
Taxes payable			64,481			26,744

Total current liabilities			485,546			427,291
Long-term debt			1,496,066			1,495,823
Deferred tax liability			490,946			536,815
Other liabilities			186,334			171,165

Total liabilities			2,658,892			2,631,094


Commitments and contingencies (Note 11)

Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)			-			-
Common stock (par value $0.01, 500,000,000 shares authorized; 143,948,370 shares issued and 139,031,570 shares outstanding at December 31, 2012; 143,944,009 shares issued and 139,027,209 shares outstanding at December 31, 2011)			1,439			1,439
Additional paid-in capital			1,983,957			1,978,369
Retained earnings			2,702,915			2,472,310
Accumulated other comprehensive gain (loss)			2,496			(4,642)
Treasury stock, at cost (4,916,800 shares of common stock at December 31, 2012 and 2011)			(114,413)			(114,413)

Total stockholders’ equity			4,576,394			4,333,063

Total liabilities and stockholders’ equity	$		7,235,286	$		6,964,157

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


		Year Ended December 31,
		2012			2011			2010
Revenues:
Contract drilling	$		2,936,066	$		3,254,313	$		3,229,736
Revenues related to reimbursable expenses			50,442			68,106			93,238

Total revenues			2,986,508			3,322,419			3,322,974


Operating expenses:
Contract drilling, excluding depreciation			1,537,224			1,548,502			1,391,086
Reimbursable expenses			48,778			66,052			91,240
Depreciation			392,913			398,612			393,177
General and administrative Impairment of assets			64,640 62,437			65,310 -			66,600 -
Bad debt recovery			(1,018)			(6,713)			(9,789)
Gain on disposition of assets			(80,844)			(4,758)			(34,714)

Total operating expenses			2,024,130			2,067,005			1,897,600


Operating income			962,378			1,255,414			1,425,374

Other income (expense):
Interest income			4,910			6,668			2,909
Interest expense			(46,216)			(73,137)			(90,698)
Foreign currency transaction gain (loss)			(1,999)			(8,588)			1,369
Other, net			(992)			(1,086)			(2,938)

Income before income tax expense			918,081			1,179,271			1,336,016

Income tax expense			(197,604)			(216,729)			(380,559)


Net income	$		720,477	$		962,542	$		955,457


Earnings per share:
Basic	$		5.18	$		6.92	$		6.87

Diluted	$		5.18	$		6.92	$		6.87


Weighted-average shares outstanding:
Shares of common stock			139,029			139,027			139,026
Dilutive potential shares of common stock			19			11			44

Total weighted-average shares outstanding			139,048			139,038			139,070


Cash dividends declared per share of common stock	$		3.50	$		3.50	$		5.25

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)


		Year Ended December 31,
		2012			2011			2010

Net income	$		720,477	$		962,542	$		955,457

Other comprehensive gains (losses), net of tax:
Foreign currency forward exchange contracts:
Unrealized holding gain (loss)			4,237			(625)			2,334
Reclassification adjustment for loss (gain) included in net income			2,733			(6,728)			(1,164)

Investments in marketable securities:
Unrealized holding gain (loss) on investments			124			(46)			343
Reclassification adjustment for loss (gain) included in net income			44			(384)			23

Total other comprehensive gain (loss)			7,138			(7,783)			1,536

Comprehensive income	$		727,615	$		954,759	$		956,993

The accompanying notes are an integral part of the consolidated financial statements

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except number of shares)


									Accumulated
					Additional				Other						Total
	Common Stock				Paid-In		Retained		Comprehensive		Treasury Stock				Stockholders’
	Shares		Amount		Capital		Earnings		Gains (Losses)		Shares		Amount		Equity

January 1, 2010		143,942,978	$	1,439	$	1,965,513	$	1,776,498	$	1,605		4,916,800	$	(114,413)	$	3,630,642

Net income		--		--		--		955,457		--		--		--		955,457
Dividends to stockholders ($5.25 per share)		--		--		--		(729,888)		--		--		--		(729,888)
Anti-dilution adjustment paid to stock plan participants ($4.75 per share)		--		--		--		(3,072)		--		--		--		(3,072)
Stock options exercised		646		--		31		--		--		--		--		31
Stock-based compensation, net of tax		--		--		7,006		--		--		--		--		7,006
Net gain on foreign currency forward exchange contracts		--		--		--		--		1,170		--		--		1,170
Net gain on investments		--		--		--		--		366		--		--		366

December 31, 2010		143,943,624		1,439		1,972,550		1,998,995		3,141		4,916,800		(114,413)		3,861,712
Net income		--		--		--		962,542		--		--		--		962,542
Dividends to stockholders ($3.50 per share)		--		--		--		(486,595)		--		--		--		(486,595)
Anti-dilution adjustment paid to stock plan participants ($3.00 per share)		--		--		--		(2,632)		--		--		--		(2,632)
Stock options exercised		385		--		--		--		--		--		--		--
Stock-based compensation, net of tax		--		--		5,819		--		--		--		--		5,819
Net loss on foreign currency forward exchange contracts		--		--		--		--		(7,353)		--		--		(7,353)
Net loss on investments		--		--		--		--		(430)		--		--		(430)

December 31, 2011		143,944,009		1,439		1,978,369		2,472,310		(4,642)		4,916,800		(114,413)		4,333,063
Net income		--		--		--		720,477		--		--		--		720,477
Dividends to stockholders ($3.50 per share)		--		--		--		(486,603)		--		--		--		(486,603)
Anti-dilution adjustment paid to stock plan participants ($3.00 per share)		--		--		--		(3,269)		--		--		--		(3,269)
Stock options exercised		4,361		--		148		--		--		--		--		148
Stock-based compensation, net of tax		--		--		5,440		--		--		--		--		5,440
Net gain on foreign currency forward exchange contracts		--		--		--		--		6,970		--		--		6,970
Net gain on investments		--		--		--		--		168		--		--		168

December 31, 2012		143,948,370	$	1,439	$	1,983,957	$	2,702,915	$	2,496		4,916,800	$	(114,413)	$	4,576,394

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2012		2011		2010

Operating activities:
Net income	$	720,477	$	962,542	$	955,457
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		392,913		398,612		393,177
Impairment of assets		62,437		--		--
Gain on disposition of assets		(80,844)		(4,758)		(34,714)
Loss (gain) on foreign currency forward exchange contracts		4,302		(7,206)		(3,307)
Deferred tax provision		(51,472)		2,141		(6,916)
Accretion of discounts on marketable securities		4,622		1,586		(648)
Stock-based compensation expense		4,357		4,956		5,928
Deferred income, net		1,767		(32,219)		17,777
Deferred expenses, net		67,824		53,317		(59,208)
Long-term employee remuneration programs		7,611		3,944		3,140
Other assets, noncurrent		(2,794)		2,220		2,477
Other liabilities, noncurrent		3,614		6,921		7,801
(Payments of) proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		(4,302)		7,206		3,307
Other		1,258		319		1,166
Changes in operating assets and liabilities:
Accounts receivable		64,056		60,785		143,096
Prepaid expenses and other current assets		(8,960)		(6,406)		1,519
Accounts payable and accrued liabilities		10,354		(9,842)		33,326
Taxes payable		114,049		(24,013)		(181,060)

Net cash provided by operating activities		1,311,269		1,420,105		1,282,318

Investing activities:
Capital expenditures (including rig construction)		(702,041)		(774,756)		(434,262)
Proceeds from disposition of assets, net of disposal costs		138,495		5,603		188,066
Proceeds from sale and maturities of marketable securities		2,725,118		5,362,138		5,450,230
Purchases of marketable securities		(2,977,290)		(5,653,665)		(5,660,518)

Net cash used in investing activities		(815,718)		(1,060,680)		(456,484)

Financing activities:
Redemption of zero coupon debentures		--		--		(4,238)
Debt issuance costs and arrangement fees		(3,838)		--		(98)
Payment of dividends		(490,245)		(490,057)		(733,661)
Other		199		4		139

Net cash used in financing activities		(493,884)		(490,053)		(737,858)

Net change in cash and cash equivalents		1,667		(130,628)		87,976
Cash and cash equivalents, beginning of year		333,765		464,393		376,417

Cash and cash equivalents, end of year	$	335,432	$	333,765	$	464,393

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC.

AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a fleet of 44 offshore drilling rigs, consisting of 32 semisubmersibles, seven jack-ups and five dynamically positioned drillships, four of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second and fourth quarters of 2014. Our semisubmersible fleet includes the Ocean Onyx and the Ocean Apex, which are currently under construction with delivery expected in the third quarter of 2013 and the second quarter of 2014, respectively. At December 31, 2012, four of our rigs were reported as “Assets held for sale” in our Consolidated Balance Sheets. Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.

As of February 18, 2013, Loews Corporation, or Loews, owned 50.4% of the outstanding shares of our common stock.

Principles of Consolidation

Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our subsidiaries after elimination of intercompany transactions and balances.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States, or U.S., or GAAP, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Reclassifications

Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications did not affect earnings.

Cash and Cash Equivalents, Marketable Securities

We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.

We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gain (loss)” until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in “Other income (expense) – Other, net.”

The effect of exchange rate changes on cash balances held in foreign currencies was not material for the years ended December 31, 2012, 2011 and 2010.

Provision for Bad Debts

We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. In establishing these reserves, we consider historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. Such provision is reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 2.

Derivative Financial Instruments

Our derivative financial instruments consist of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions. Designated hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value are recorded as a component of “Accumulated other comprehensive gain (loss),” or AOCGL, in our Consolidated Balance Sheets. The effective portion of the cash flow hedge will remain in AOCGL until it is reclassified into earnings in the period or periods during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. We report such realized gains and losses as a component of “Contract drilling, excluding depreciation” expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate.

Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value and realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. See Notes 6 and 7.

Assets Held For Sale

In late 2012, our management adopted a plan to actively market for sale three of our mid-water semisubmersibles, consisting of two previously cold-stacked rigs (the Ocean Epoch and Ocean New Era) and the Ocean Whittington, which was idled in 2012, and the Ocean Spartan, a previously cold- stacked jack-up rig. This decision was based on management’s review of our drilling fleet and their assessment that each of the previously cold-stacked rigs had been idle for approximately two or more years and that it was unlikely that these rigs would find short-term work due to their age and capabilities compared to expected short-term market demand. In addition, the Ocean Whittington, which returned to the U.S. Gulf of Mexico, or GOM, during 2012 subsequent to the end of its contract in Brazil, was evaluated for upgrade to operate in the North Sea or for returning to service in the GOM or elsewhere in its current configuration. At the end of 2012, management had determined that none of these options for the Ocean Whittington were economically feasible, and the rig was cold stacked and put on the market for sale.

In connection with the reclassification of these rigs to “Assets held for sale,” we determined that the carrying values of the mid-water semisubmersible rigs in the disposal group were impaired as the carrying value for each exceeded its aggregate fair value. We measured fair value for each rig in the disposal group using an expected present value technique that utilizes significant unobservable inputs, representing a Level 3 fair value measurement, which includes assumptions for estimated proceeds that may be received on disposition of the rig and estimated costs to sell. Based on this probability-weighted cash flow analysis, we recognized an impairment loss of $62.4 million in the fourth quarter of 2012. We determined that the carrying value of the Ocean Spartan was not impaired. At December 31, 2012, we reported “Assets held for sale” aggregating $11.6 million in our Consolidated Balance Sheets. See Note 7.

Drilling and Other Property 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, 2012 and 2011, we capitalized $220.3 million and $269.5 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $60 million per project.

Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations as “Gain on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.

Capitalized Interest

We capitalize interest cost for the construction and upgrade of qualifying assets. During 2012 and 2011 we capitalized interest on qualifying expenditures, primarily related to our rig construction projects. See Note 8. There were no qualifying expenditures during 2010.

A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:


	For the Year Ended December 31,
	2012			2011			2010

	(In thousands)
Total interest cost including amortization of debt issuance costs	$	83,890		$	84,349		$	90,698
Capitalized interest		(37,674	)		(11,212	)		--

Total interest expense as reported	$	46,216		$	73,137		$	90,698

Asset Retirement Obligations

At December 31, 2012 and 2011, we had no asset retirement obligations.

Impairment of Long-Lived Assets

•

dayrate by rig;

•

utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);

•

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

•

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

•

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

•

salvage value for each rig; and

•

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

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.

During 2012, we sold four jack-up rigs that were cold stacked at December 31, 2011 at prices in excess of their net book value and began construction of a moored semisubmersible rig, the Ocean Apex, utilizing the hull of one of our mid-water floaters that was also cold stacked at December 31, 2011. The remaining three cold-stacked rigs at December 31, 2011 (two mid-water floaters and one jack-up rig) were transferred to “Assets held for sale” in December 2012.

A summary of our cold-stacked rigs evaluated for impairment at December 31, 2012, 2011 and 2010 is as follows:


	December 31,
	2012		2011		2010

	(In millions, except number of rigs)
Mid-Water floaters		--		3		3
Jack-ups		--		5		4

Total		--		8		7

Aggregate net book value	$	--	$	76.5	$	78.0

We performed an impairment review for each of these rigs using the methodology described above and concluded that these eight and seven rigs were not subject to impairment at December 31, 2011 and 2010, respectively. There were no cold-stacked rigs at December 31, 2012 that were not being marketed for sale.

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.

Fair Value of Financial Instruments

We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. For non-current financial instruments we use quoted market prices, when available, and discounted cash flows to estimate fair value. See Note 7.

Debt Issuance Costs

Debt issuance costs are included in our Consolidated Balance Sheets in “Other assets” and are amortized over the respective terms of the related debt.

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 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.

We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. See Note 13.

Treasury Stock

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during 2012, 2011 or 2010.

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive income (loss) for the three years ended December 31, 2012, 2011 and 2010 includes net income (loss) and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges. See Note 10.

Foreign Currency

Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations and include, when applicable, unrealized gains and losses to record the carrying value of our FOREX contracts not designated as accounting hedges, as well as realized gains and losses from the settlement of such contracts. For the years ended December 31, 2012, 2011 and 2010, we recognized aggregate net foreign currency gains (losses) of $(2.0) million, $(8.6) million and $1.4 million, respectively. See Note 6.

Revenue Recognition

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.

Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (either lump-sum or dayrate). These fees are generally earned as services are performed over the initial term of the related drilling contracts. We defer contract preparation fees received, as well as direct and incremental costs associated with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related drilling contracts (which we estimate to be benefited from the contract preparation activity).

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 received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

We record reimbursements received 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, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

2. Supplemental Financial Information

Consolidated Balance Sheet Information

Accounts receivable, net of allowance for bad debts, consists of the following:


	December 31,
	2012		2011

	(In thousands)
Trade receivables	$	478,992	$	555,451
Value added tax receivables		13,884		11,615
Amounts held in escrow		11,555		12
Interest receivable		6		2,540
Related party receivables		527		577
Other		154		606

		505,118		570,801
Allowance for bad debts		(5,458)		(6,867)

Total	$	499,660	$	563,934

An analysis of the changes in our provision for bad debts for each of the three years ended December 31, 2012, 2011 and 2010 is as follows:


	For the Year Ended December 31,
	2012		2011		2010

	(In thousands)

Allowance for bad debts, beginning of year	$	6,867	$	31,908	$	41,698
Bad debt expense:
Provision for bad debts		--		5,688		--
Recovery of bad debts		(1,018)		(12,401)		(9,789)

Total bad debt expense (recovery)		(1,018)		(6,713)		(9,789)
Write off of uncollectible accounts against reserve		(391)		(18,380)		--
Other		--		52		(1)

Allowance for bad debts, end of year	$	5,458	$	6,867	$	31,908

Prepaid expenses and other current assets consist of the following:


	December 31,
	2012		2011

	(In thousands)

Rig spare parts and supplies	$	57,558	$	52,637
Deferred mobilization costs		38,074		74,659
Prepaid insurance		12,549		12,417
Deferred tax assets		8,619		6,800
Prepaid taxes		5,950		37,612
FOREX contracts		3,627		1,262
Other		9,722		7,183

Total	$	136,099	$	192,570

Accrued liabilities consist of the following:


	December 31,
	2012		2011

	(In thousands)

Rig operating expenses	$	70,078	$	108,342
Payroll and benefits		88,612		77,055
Deferred revenue		71,699		67,894
Accrued capital project/upgrade costs		56,595		22,725
Interest payable		21,219		21,406
Construction milestone payments		--		14,600
Personal injury and other claims		10,312		10,536
FOREX contracts		29		8,454
Other		5,890		5,388

Total	$	324,434	$	336,400

At December 31, 2011 we had accrued $14.6 million for the first milestone payment related to the construction of the Ocean Onyx. See Notes 8 and 11.

Consolidated Statement of Cash Flows Information

Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows:


	December 31,
	2012		2011		2010

	(In thousands)
Accrued but unpaid capital expenditures at December 31	$	56,595	$	37,325	$	28,947
Income tax benefits related to exercise of stock options		1,083		863		1,078
Cash interest payments, including amounts capitalized ⁽¹⁾		46,156		71,884		84,370
Cash income taxes paid, net of refunds:
U.S. federal		71,000		94,843		427,504
Foreign		72,249		150,465		128,447
State		243		210		111

(1)

Interest paid included $0.2 million and $0.9 million in interest on Internal Revenue Service assessments during the years ended December 31, 2012 and 2010, respectively.

3. Stock-Based Compensation

Our Second Amended and Restated 2000 Stock Option Plan, as amended, or Stock Plan, provides for the issuance of either incentive stock options or non-qualified stock options to our employees, consultants and non-employee directors. Our Stock Plan also authorizes the award of stock appreciation rights, or SARs, in tandem with stock options or separately. The maximum aggregate number of shares of our common stock for which stock options or SARs may be granted is 1,500,000 shares. The exercise price per share may not be less than the fair market value of the common stock on the date of grant. Generally, stock options and SARs vest ratably over a four year period and expire in ten years.

Total compensation cost recognized for Stock Plan transactions, consisting solely of awards of SARs, for the years ended December 31, 2012, 2011 and 2010 was $4.7 million, $5.0 million and $6.0 million, respectively. Tax benefits recognized for the years ended December 31, 2012, 2011 and 2010 related thereto were $1.6 million, $1.7 million and $2.0 million, respectively.

The fair value of SARs granted under the Stock Plan during each of the years ended December 31, 2012, 2011 and 2010 was estimated using the Black Scholes pricing model.

The following are the weighted average assumptions used in estimating the fair value of our SARs:


	Year Ended December 31,
	2012			2011			2010

Expected life of SARs (in years)		6			5			5
Expected volatility		33.45	%		30.37	%		35.99%
Dividend yield		.78	%		.76	%		.70%
Risk free interest rate		.89	%		1.54	%		1.88%

Expected life of SARs is based on historical data as is the expected volatility. The dividend yield is based on the current approved regular dividend rate in effect and the current market price at the time of grant. Risk free interest rates are determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected life of the SARs.

A summary of activity under the Stock Plan as of December 31, 2012 and changes during the year then ended is as follows:


	Number of Awards		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (Years)		Aggregate Intrinsic Value (In Thousands)

Awards outstanding at January 1, 2012		998,160	$	85.01
Granted		282,200	$	64.33
Exercised		(9,968)	$	51.57
Forfeited		(4,644)	$	68.73
Expired		(36,268)	$	94.14

Awards outstanding at December 31, 2012		1,229,480	$	80.32		7.0	$	3,515

Awards exercisable at December 31, 2012		810,457	$	86.86		6.0	$	2,141

The weighted-average grant date fair values per share of awards granted during the years ended December 31, 2012, 2011 and 2010 were $19.01, $18.17 and $23.62, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2012, 2011 and 2010 was $147,000, $28,000 and $8,000, respectively. The total fair value of awards vested during the years ended December 31, 2012, 2011 and 2010 was $5.2 million, $5.4 million and $6.6 million, respectively. As of December 31, 2012 there was $6.3 million of total unrecognized compensation cost related to nonvested stock awards granted under the Stock Plan which we expect to recognize over a weighted average period of 2.6 years.

4. Earnings Per Share

A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:


	Year Ended December 31,
	2012		2011		2010

	(In thousands, except per share data)

Net income – basic (numerator):	$	720,477	$	962,542	$	955,457
Effect of dilutive potential shares
Convertible debentures		--		--		56


Net income including conversions – diluted (numerator):	$	720,477	$	962,542	$	955,513


Weighted-average shares – basic (denominator):		139,029		139,027		139,026
Effect of dilutive potential shares
Convertible debentures		--		--		21
Stock options and stock appreciation rights		19		11		23

Weighted-average shares including conversions – diluted (denominator):		139,048		139,038		139,070


Earnings per share:
Basic	$	5.18	$	6.92	$	6.87

Diluted	$	5.18	$	6.92	$	6.87

The following table sets forth the share effects of stock options and the number of stock appreciation rights excluded from our computations of diluted earnings per share, or EPS, as the inclusion of such potentially dilutive shares would have been antidilutive for the periods presented:


	Year Ended December 31,

	2012		2011		2010

	(In thousands)
Employee and director:
Stock options		18		19		11
Stock appreciation rights		853		847		584

5. Marketable Securities

We report our investments in marketable securities as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 7.

Our investments in marketable securities are classified as available for sale and are summarized as follows:


	December 31, 2012

	Amortized Cost		Unrealized Gain (Loss)		Market Value

	(In thousands)

U.S. Treasury Bills and Notes (due within one year)	$	1,149,707	$	150	$	1,149,857
Mortgage-backed securities		276		25		301

Total	$	1,149,983	$	175	$	1,150,158


	December 31, 2011

	Amortized Cost		Unrealized Gain (Loss)			Market Value

	(In thousands)

U.S. Treasury Bills and Notes (due within one year)	$	902,042	$	(59	)	$	901,983
Mortgage-backed securities		394		37			431

Total	$	902,436	$	(22	)	$	902,414

Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:


	Year Ended December 31,

	2012			2011			2010

	(In thousands)
Proceeds from maturities	$	2,575,000		$	5,350,000		$	5,450,000
Proceeds from sales		150,118			12,138			230
Gross realized gains		--			784			0
Gross realized losses		(6	)		(5	)		(7)

6. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize FOREX contracts to manage our foreign exchange risk. Our FOREX contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.

We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency gains and losses on future foreign currency expenditures. The amount and duration of such contracts is based on our monthly forecast of expenditures in the significant currencies in which we do business and for which there is a financial market (i.e., Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner). These forward contracts are derivatives as defined by GAAP.

During the years ended December 31, 2012, 2011 and 2010, we settled FOREX contracts with aggregate notional values of approximately $305.6 million, $318.9 million and $332.5 million, respectively, of which the entire aggregate amounts were designated as an accounting hedge. During the years ended December 31, 2012, 2011 and 2010, we did not enter into or settle any FOREX contracts that were not designated as accounting hedges.

The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as hedging instruments for the years ended December 31, 2012, 2011 and 2010.


	Amount of (Loss) Gain Recognized in Income

	For the Years Ended December 31,
Location of (Loss) Gain Recognized in Income	2012			2011		2010

	(In thousands)
Contract drilling expense	$	(4,302	)	$	7,206	$	3,307

As of December 31, 2012, we had FOREX contracts outstanding in the aggregate notional amount of $144.2 million, consisting of $12.2 million in Australian dollars, $72.9 million in Brazilian reais, $42.2 million in British pounds sterling and $16.9 million in Mexican pesos. These contracts generally settle monthly through September 2013. As of December 31, 2012, all outstanding derivative contracts had been designated as cash flow hedges.

The following table presents the fair values of our derivative financial instruments at December 31, 2012 and 2011.


Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
	December 31, 2012		December 31, 2011			December 31, 2012			December 31, 2011
	(In thousands)					(In thousands)
Prepaid expenses and other current assets	$	3,627	$	1,262	Accrued liabilities	$	(29	)	$	(8,454)

The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our FOREX contracts designated as cash flow hedges for the years ended December 31, 2012, 2011 and 2010.


	For the years ended December 31,

	2012			2011			2010

	(In thousands)
Amount of gain (loss) recognized in AOCGL on derivative (effective portion)	$	6,519		$	(962	)	$	3,591
Location of (loss) gain reclassified from AOCGL into income (effective portion)		Contract drilling, excluding depreciation			Contract drilling, excluding depreciation			Contract drilling, excluding depreciation
Amount of (loss) gain reclassified from AOCGL into income (effective portion)	$	(4,205	)	$	10,351		$	1,790
Location of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)
Amount of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	$	(17	)	$	(85	)	$	--

As of December 31, 2012, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $3.6 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense to the extent fully effective.

7. Financial Instruments and Fair Value Disclosures

Concentrations of Credit and Market Risk

Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including mortgage-backed securities. We generally place our excess cash investments in U.S. government backed short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.

Most of our investments in debt securities are U.S. government securities with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. Our two largest customers in Brazil, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government) and OGX Petróleo e Gás Ltda. (a privately owned Brazilian oil and natural gas company), accounted for $116.4 million and $80.3 million, or 24% and 17%, respectively, of our total consolidated gross trade accounts receivable balances as of December 31, 2012, and $110.4 million and $69.4 million, or 20% and 12%, respectively, as of December 31, 2011.

At December 31, 2012 and 2011, $17.2 million and $95.8 million, respectively, was payable to us from a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties, which we believe is a real property interest and has been presented in “Accounts receivable, net of allowance for bad debts” in our Consolidated Balance Sheets. Our drilling program related to the NPI arrangement was completed in 2011. The customer who conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code on August 17, 2012. Certain parties (including the debtor) in the bankruptcy proceedings have questioned whether our NPI, and certain amounts we have received and expect to receive under it since the filing of the bankruptcy, should be included in the debtor’s estate under the bankruptcy proceeding. We have filed a declaratory judgment action in the bankruptcy court seeking a declaration that our NPI, and payments that we have received and expect to receive from it since the filing of the bankruptcy, are not part of the bankruptcy estate, and we will vigorously defend our rights and pursue our interests in this matter. We believe we will collect all of the receivable due to us from the NPI and, accordingly, have recorded no reserve for this receivable as of December 31, 2012.

In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. Historically, we have not experienced significant losses on our trade receivables. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. Our allowance for bad debts was $5.5 million and $6.9 million at December 31, 2012 and 2011, respectively. See Note 2.

Fair Values

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:


Level 1		Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds, U.S. Treasury Bills and Treasury notes. Our Level 1 assets at December 31, 2012 consisted of cash held in money market funds of $284.9 million and investments in U.S. Treasury securities of $1,149.9 million. Our Level 1 assets at December 31, 2011 consisted of cash held in money market funds of $303.9 million and investments in U.S. Treasury securities of $902.0 million.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include residential mortgage-backed securities and over-the-counter FOREX contracts. Our residential mortgage-backed securities were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.

Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at December 31, 2012 consisted of nonrecurring measurements of certain rigs held for sale for which we recorded an impairment loss.

Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period.

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. Assets and liabilities measured at fair value are summarized below:


	December 31, 2012

	Fair Value Measurements Using										Total Losses
	Level 1		Level 2			Level 3		Assets at Fair Value			for Year Ended

	(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments	$	1,434,751	$	--		$	--	$	1,434,751		$	--
FOREX contracts		--		3,627			--		3,627			--
Mortgage-backed securities		--		301			--		301			--

Total assets	$	1,434,751	$	3,928		$	--	$	1,438,679		$	--



Liabilities:
FOREX contracts	$	--	$	(29	)	$	--	$	(29	)	$	--



Nonrecurring fair value measurements:
Assets:
Assets held for sale	$	--	$	--		$	3,900	$	3,900		$	(62,437)



	December 31, 2011
	Fair Value Measurements Using										Total Losses
	Level 1		Level 2			Level 3		Assets at Fair Value			for Year Ended

	(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments	$	1,205,925	$	--		$	--	$	1,205,925		$	--
FOREX contracts		--		1,262			--		1,262			--
Mortgage-backed securities		--		431			--		431			--

Total assets	$	1,205,925	$	1,693		$	--	$	1,207,618		$	--



Liabilities:
FOREX contracts	$	--	$	(8,454	)	$	--	$	(8,454	)	$	--

We have presented the loss related to assets held for sale in “Impairment of assets” in our Consolidated Statements of Operations for the year ended December 31, 2012.

We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt), which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the following assumptions:

•

Cash and cash equivalents -- The carrying amounts approximate fair value because of the short maturity of these instruments.

•

Accounts receivable and accounts payable -- The carrying amounts approximate fair value based on the nature of the instruments.

We consider our long-term debt to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our 5.70% Senior Notes due 2039, 5.875% Senior Notes due 2019, 4.875% Senior Notes due July 1, 2015, and 5.15% Senior Notes due September 1, 2014 was derived using a third-party pricing service at December 31, 2012 and quoted closing market prices from brokers of these instruments at December 31, 2011. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring around the report date. Fair values and related carrying values of our long-term debt instruments are shown below.



	December 31, 2012				December 31, 2011

	Fair Value		Carrying Value		Fair Value		Carrying Value

	(In millions)
4.875% Senior Notes	$	275.5	$	249.8	$	272.9	$	249.8
5.15% Senior Notes		269.0		249.9		272.7		249.8
5.70% Senior Notes		641.4		496.9		555.0		496.8
5.875% Senior Notes		617.1		499.5		575.4		499.4

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.

8. Drilling and Other Property and Equipment

Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:


	December 31,

	2012			2011

	(In thousands)
Drilling rigs and equipment	$	7,107,279		$	7,431,713
Construction work-in-progress		990,964			504,805
Land and buildings		64,296			60,926
Office equipment and other		60,239			49,035

Cost		8,222,778			8,046,479
Less accumulated depreciation		(3,357,806	)		(3,379,010)

Drilling and other property and equipment, net	$	4,864,972		$	4,667,469

During 2012, we entered into contracts for the construction of a fourth drillship, the Ocean BlackLion, and the Ocean Apex, a deepwater floater rig. Construction work-in-progress, including capitalized interest, at December 31, 2012 included $741.1 million, $167.4 million and $82.5 million related to the construction of our four drillships, the Ocean Onyx, and the Ocean Apex, respectively.

Construction work-in-progress, including capitalized interest, at December 31, 2011 included $14.6 million and $490.2 million related to the construction of the Ocean Onyx and the first three of our four drillships, respectively. See Note 11.

During 2012, we sold six of our jack-up rigs for an aggregate pre-tax gain of approximately $76.5 million and retired the aggregate net book value of $55.4 million. In addition, in December 2012, we transferred four of our drilling rigs with an aggregate net book value of $73.2 million to “Assets held for sale” in our Consolidated Balance Sheets. See Note 1.

9. Credit Agreement and Long-Term Debt

Credit Agreement

On September 28, 2012, we entered into a syndicated 5-Year Revolving Credit Agreement, or Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent and swingline lender. The Credit Agreement provides for a $750 million senior unsecured revolving credit facility, for general corporate purposes, maturing on

September 28, 2017. The entire amount of the facility is available for revolving loans. Up to $250 million of the facility is available for the issuance of performance or other standby letters of credit and up to $75 million is available for swingline loans.

Revolving loans under the Credit Agreement bear interest, at our option, at a rate per annum based on either an alternate base rate, or ABR, or a Eurodollar Rate, as defined in the Credit Agreement, plus the applicable interest margin for an ABR loan or a Eurodollar loan. The ABR is the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the daily one-month Eurodollar Rate plus 1.00%. The applicable interest margin for ABR loans varies from 0% to 0.25%, based on our current credit ratings. The applicable interest margin for Eurodollar loans varies between 0.75% and 1.25%, based on our current credit ratings.

Swingline loans bear interest, at our option, at a rate per annum equal to (i) the ABR plus the applicable interest margin for ABR loans or (ii) the daily one-month Eurodollar Rate plus the applicable interest margin for Eurodollar loans.

Under our Credit Agreement, we also pay, based on our current credit ratings, and as applicable, other customary fees including, but not limited to, a commitment fee on the unused commitments under the Credit Agreement, varying between 0.06% and 0.20% per annum, and a fronting fee to the issuing bank for each letter of credit. Participation fees for letters of credit are dependent upon the type of letter of credit issued, varying between 0.375% and 0.625% per annum for performance letters of credit, and between 0.75% and 1.25% per annum for all other letters of credit. Changes in credit ratings could lower or raise the fees that we pay under the Credit Agreement.

The Credit Agreement contains customary covenants including, but not limited to, maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Agreement, of not more than 60% at the end of each fiscal quarter, as well as limitations on liens; mergers, consolidations, liquidation and dissolution; changes in lines of business; swap agreements; transactions with affiliates; and subsidiary indebtedness.

Based on our current credit ratings at December 31, 2012, the applicable margin on ABR loans and Eurodollar loans would have been 0.00% and 1.00%, respectively. As of December 31, 2012, there were no amounts outstanding under the Credit Agreement.

Long-term Debt

Our long-term debt is comprised as follows:


Name of Issue	Aggregate Principal Amount (In millions)	Maturity Date	Stated Interest Rate	Semiannual Interest Payment Dates

5.15% Senior Notes	$250.0	September 1, 2014	5.15%	March 1 and September 1
4.875% Senior Notes	$250.0	July 1, 2015	4.875%	January 1 and July 1
5.875% Senior Notes	$500.0	May 1, 2019	5.875%	May 1 and November 1
5.70% Senior Notes	$500.0	October 15, 2039	5.70%	April 15 and October 15

Our 5.70% Senior Notes, 5.875% Senior Notes, 4.875% Senior Notes and 5.15% Senior Notes are all unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to its existing and future unsecured and unsubordinated indebtedness, and will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these notes for cash at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

The effective interest rate for each of our senior notes approximates the stated coupon interest rate.

At December 31, 2012 and 2011, the carrying value of our long-term debt was as follows:


	December 31,

	2012		2011

	(In thousands)
5.15% Senior Notes	$	249,882	$	249,811
4.875% Senior Notes		249,837		249,779
5.875% Senior Notes		499,480		499,414
5.70% Senior Notes		496,867		496,819

Total long-term debt	$	1,496,066	$	1,495,823

As of December 31, 2012, the aggregate annual maturity of our long-term debt was as follows:


	Aggregate Principal Amount
Years Ending December 31,	(In thousands)
2013	$	--
2014		250,000
2015		250,000
2016		--
2017		--
Thereafter		1,000,000

Total maturities of long-term debt, excluding unamortized discounts		1,500,000
Total unamortized discounts		(3,934)

Total long-term debt	$	1,496,066

10. Other Comprehensive Income (Loss)

The components of our other comprehensive income (loss) and the associated income tax effects allocated to such components are as follows:


	Year Ended December 31, 2012
	Before Tax		Tax Effect			Net-of-Tax

	(In thousands)
FOREX contracts:
Unrealized holding gain	$	6,519	$	(2,282	)	$	4,237
Reclassification adjustment for loss included in net income		4,205		(1,472	)		2,733

Net unrealized gain on FOREX contracts		10,724		(3,754	)		6,970

Investments in marketable securities:
Unrealized holding gain		152		(28	)		124
Reclassification adjustment for loss included in net income		45		(1	)		44

Net unrealized gain on marketable securities		197		(29	)		168


Other comprehensive income	$	10,921	$	(3,783	)	$	7,138


	Year Ended December 31, 2011
	Before Tax			Tax Effect			Net-of-Tax

	(In thousands)
FOREX contracts:
Unrealized holding loss	$	(962	)	$	337		$	(625)
Reclassification adjustment for gain included in net income		(10,351	)		3,623			(6,728)

Net unrealized loss on FOREX contracts		(11,313	)		3,960			(7,353)

Investments in marketable securities:
Unrealized holding loss		(61	)		15			(46)
Reclassification adjustment for gain included in net income		(589	)		205			(384)

Net unrealized loss on marketable securities		(650	)		220			(430)


Other comprehensive loss	$	(11,963	)	$	4,180		$	(7,783)


	Year Ended December 31, 2010
	Before Tax			Tax Effect			Net-of-Tax

	(In thousands)
FOREX contracts:
Unrealized holding gain	$	3,591		$	(1,257	)	$	2,334
Reclassification adjustment for gain included in net income		(1,790	)		626			(1,164)

Net unrealized gain on FOREX contracts		1,801			(631	)		1,170

Investments in marketable securities:
Unrealized holding gain		528			(185	)		343
Reclassification adjustment for loss included in net income		36			(13	)		23

Net unrealized gain on marketable securities		564			(198	)		366


Other comprehensive income	$	2,365		$	(829	)	$	1,536

We have presented the reclassification adjustments for gains (losses) for FOREX contracts and investments in marketable securities in “Contract drilling, excluding depreciation” and “Other, net,” respectively, in our Consolidated Statements of Operations.

The components of our accumulated other comprehensive income (loss) included in our Consolidated Balance Sheets are as follows:


	Unrealized Gain (Loss) on						Total Other
	FOREX Contracts			Marketable Securities			Comprehensive Income (Loss)

	(In thousands)
Balance at January 1, 2011	$	2,733		$	408		$	3,141
Other comprehensive loss		(7,353	)		(430	)		(7,783)

Balance at December 31, 2011		(4,620	)		(22	)		(4,642)
Other comprehensive gain		6,970			168			7,138

Balance at December 31, 2012	$	2,350		$	146		$	2,496

11. Commitments and Contingencies

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.

Litigation. We are one of several unrelated defendants in lawsuits filed in state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted and we expect to receive complete defense and indemnity with respect to a majority of the lawsuits from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. We also believe that we are not liable for the damages asserted in the remaining lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation, and we filed a declaratory judgment action in Texas state court against NuStar Energy LP, or NuStar, the successor to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. We obtained summary judgment on our claims in the declaratory judgment action, but NuStar has appealed the court’s decision. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations and cash flows.

Various other claims have been filed against us in the ordinary course of business. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial condition, results of operations and cash flows.

We intend to defend these matters vigorously; however, we cannot predict with certainty the outcome or effect of any litigation matters specifically described above or any other pending litigation or claims. There can be no assurance as to the ultimate outcome of these lawsuits.

Personal Injury Claims. Our deductibles for marine liability insurance coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims 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. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2012, our estimated liability for personal injury claims was $36.1 million, of which $9.9 million and $26.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2011, our estimated liability for personal injury claims was $32.7 million, of which $10.1 million and $22.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

•

the severity of personal injuries claimed;

•

significant changes in the volume of personal injury claims;

•

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

•

inconsistent court decisions; and

•

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

Purchase Obligations.

Drillship Construction. We are financially obligated under four separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of four ultra-deepwater drillships, including one contract which we entered into in May 2012. Delivery of our drillships is scheduled for the second and fourth quarters of 2013 and the second and fourth quarters of 2014. The aggregate cost of the four drillships, including commissioning, spares and project management, is expected to be approximately $2.6 billion.

Ocean Onyx Construction. We are obligated under a vessel modification agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of the Ocean Onyx. The rig is under construction in Brownsville, Texas and is expected to be delivered in the third quarter of 2013. We estimate the aggregate cost for the construction of the Ocean Onyx to be approximately $310.0 million, including commissioning, spares and project management costs. The contracted price due to Keppel is payable in 11 installments based on the occurrence of certain events as detailed in the vessel modification agreement. The first milestone payment in the amount of $14.6 million was payable upon signing of the agreement and was accrued in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2011. We paid the first five installments, aggregating $65.7 million, during 2012.

At December 31, 2012 and 2011, we had no other purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.

Operating Leases. We lease office and yard facilities, housing, equipment and vehicles under operating leases, which expire at various times through the year 2017. Total rent expense amounted to $10.8 million, $9.3 million and $8.0 million for the years ended December 31, 2012, 2011 and 2010, respectively. Future minimum rental payments under leases are approximately $2.5 million and $1.6 million for the years 2013 and 2014, respectively, and $0.2 million in the aggregate for the years 2015 to 2017. There are no minimum future rental payments under operating leases after 2017.

Letters of Credit and Other. We were contingently liable as of December 31, 2012 in the amount of $126.5 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $111.5 million of performance and tax appeal bonds can require collateral at any time. As of December 31, 2012, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.

12. Related-Party Transactions

Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include personnel, internal auditing, accounting, and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $0.8 million, $1.1 million and $1.3 million by Loews for these support functions during the years ended December 31, 2012, 2011 and 2010, respectively.

Transactions with Other Related Parties. We hire marine vessels and helicopter transportation services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc. The Executive Chairman of the Board of Directors of SEACOR Holdings Inc. is also a member of our Board of Directors. For the years ended December 31, 2012, 2011 and 2010, we paid $0.1 million, $0.1 million and $3.1 million, respectively, for the hire of such vessels and such services.

During the years ended December 31, 2012, 2011 and 2010 we made payments of $1.0 million, $1.2 million and $1.0 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Executive Officer is an audit partner at this firm.

13. Income Taxes

Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. 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 $2.0 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 practical to estimate this potential liability.

In 2010, we provided $15.0 million for U.S. taxes attributable to undistributed earnings of Diamond East Asia Limited, or DEAL, a wholly owned subsidiary of DOIL, as it had been our intention to repatriate its earnings to the U.S. However, a tax law provision that expired at the end of 2009, but was subsequently signed back into law in late 2010, in conjunction with our decisions at that time to build three new drillships overseas, caused us to reassess our intent to repatriate the earnings of DEAL to the U.S. We now intend to indefinitely reinvest the earnings of DEAL internationally through another of our foreign subsidiaries, and, consequently, we are no longer providing U.S. income taxes on its earnings. During 2011, we reversed the $15.0 million of U.S. income taxes that had been provided in 2010 for the earnings of DEAL.

The components of income tax expense (benefit) are as follows:


	Year Ended December 31,

	2012			2011			2010

	(In thousands)
Federal – current	$	173,061		$	109,684		$	183,825
State – current		267			264			191
Foreign – current		75,748			104,640			203,459

Total current		249,076			214,588			387,475


Federal – deferred		(51,852	)		(1,023	)		8,287
Foreign – deferred		380			3,164			(15,203)

Total deferred		(51,472	)		2,141			(6,916)

Total	$	197,604		$	216,729		$	380,559

The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following:


	Year Ended December 31,

	2012			2011			2010

	(In thousands)
Income before income tax expense:
U.S.	$	512,733		$	486,393		$	755,982
Foreign		405,348			692,878			580,034

Worldwide	$	918,081		$	1,179,271		$	1,336,016


Expected income tax expense at federal statutory rate	$	321,328		$	412,745		$	467,606
Foreign earnings of foreign subsidiaries (not taxed at the statutory federal income tax rate) net of related foreign taxes		(166,251	)		(189,051	)		(191,789)
Foreign earnings of foreign subsidiaries for which U.S. federal income taxes have been provided		28,252			(14,681	)		29,736
Foreign taxes of domestic and foreign subsidiaries for which U.S. federal income taxes have also been provided		35,722			65,521			119,009
Foreign tax credits		(45,824	)		(67,232	)		(89,809)
Interest capitalized by foreign subsidiaries		(11,764	)		(3,924	)		--
Reduction of deferred tax liability related to a goodwill deduction resulting from a prior period stock acquisition		--			(2,950	)		(8,850)
Uncertain tax positions		6,325			(7,733	)		30,950
Amortization of deferred charges associated with intercompany rig sales to other tax jurisdictions		31,276			29,556			30,442
Net expense (benefit) in connection with resolutions of tax issues and adjustments relating to prior years		(2,152	)		(6,085	)		(7,346)
Other		692			563			610

Income tax expense	$	197,604		$	216,729		$	380,559

Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows:


	December 31,

	2012			2011

	(In thousands)
Deferred tax assets:
Net operating loss carryforwards, or NOLs	$	24,067		$	27,212
Worker’s compensation and other current accruals (1)		16,929			15,487
Disputed receivables reserved		956			6
Deferred compensation		9,051			4,504
Foreign contribution taxes		6,780			5,615
Mobilization		4,736			--
Nonqualified stock options and SARs		8,698			7,538
Other		1,640			2,212

Total deferred tax assets		72,857			62,574
Valuation allowance for NOLs		(22,876	)		(26,353)

Net deferred tax assets		49,981			36,221

Deferred tax liabilities:
Depreciation		(526,606	)		(558,915)
Unbilled revenue		(5,649	)		(3,216)
Mobilization		--			(3,939)
Undistributed earnings of foreign subsidiaries		(24	)		(24)
Other		(29	)		(141)

Total deferred tax liabilities		(532,308	)		(566,235)

Net deferred tax liability	$	(482,327	)	$	(530,014)

(1)

$8.6 million and $6.8 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2012 and 2011, respectively. See Note 2.

We record a valuation allowance to derecognize a portion of our deferred tax assets, which we do not expect to be ultimately realized. A summary of changes in the valuation allowance is as follows:


	For the Year Ended December 31,

	2012			2011			2010

	(In thousands)
Valuation allowance as of January 1	$	26,353		$	32,102		$	30,975
Establishment of valuation allowances:
Foreign tax credits		--			(186	)		79
Net operating losses		946			1,844			13,381
Releases of valuation allowances in various jurisdictions		(4,423	)		(7,407	)		(12,333)

Valuation allowance as of December 31	$	22,876		$	26,353		$	32,102

Net Operating Loss Carryforwards – As of December 31, 2012, we had recorded a deferred tax asset of $24.1 million for the benefit of NOL carryforwards related to our international operations. Approximately $7.5 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $16.6 million relates to NOL carryforwards of our Mexican entities. Unless utilized, the tax benefits of these Mexican NOL carryforwards will expire between 2013 and 2021 as follows:


Year Expiring	Tax Benefit of NOL Carryforwards (In millions)

2013	$	0.1
2014		3.9
2015		4.3
2016		4.6
2017		3.2
2018		--
2019		--
2020		--
2021		0.5

Total	$	16.6

As of December 31, 2012, a valuation allowance of $22.9 million has been recorded for our NOLs as only $1.2 million of the deferred tax asset is more likely than not to be realized.

Unrecognized Tax Benefits. Our income tax returns are subject to review and examination in the various jurisdictions in which we operate and we are currently contesting various tax assessments. We accrue for income tax contingencies, or uncertain tax positions, that we believe are more likely than not exposures. A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding interest and penalties, is as follows:


	For the Year Ended December 31,

	2012			2011			2010

	(In thousands)
Balance, beginning of period	$	(41,241	)	$	(45,936	)	$	(27,008)
Additions for current year tax positions		(6,790	)		(900	)		(3,164)
Additions for prior year tax positions		(2,610	)		--			(15,764)
Reductions for prior year tax positions		2,288			1,851			--
Reductions related to statute of limitation expirations		--			3,744			--

Balance, end of period	$	(48,353	)	$	(41,241	)	$	(45,936)

At December 31, 2012, $7.0 million and $55.4 million of the net liability for uncertain tax positions were reflected in “Other assets” and “Other liabilities,” respectively. At December 31, 2011, $7.2 million and $48.4 million of the net liability for uncertain tax positions were reflected in “Other assets” and “Other liabilities,” respectively. Of the net unrecognized tax benefits at December 31, 2012, 2011 and 2010, all $48.4 million, $41.2 million and $45.9 million, respectively, would affect the effective tax rates if recognized.

The following table presents the amount of accrued interest and penalties at December 31, 2012 and 2011 related to uncertain tax positions:


	December 31,

	2012			2011

	(In thousands)
Uncertain tax positions, excluding interest and penalties	$	(48,353	)	$	(41,241)
Accrued interest on uncertain tax positions		(7,029	)		(8,931)
Accrued penalties on uncertain tax positions		(21,662	)		(22,449)

Uncertain tax positions, including interest and penalties	$	(77,044	)	$	(72,621)

We record interest related to accrued uncertain tax positions in interest expense and recognize penalties associated with uncertain tax positions in tax expense. Interest expense and penalties recognized during the three years ended December 31, 2012 related to uncertain tax positions are as follows:


	For the Year Ended December 31,

	2012			2011			2010

	(In thousands)
Net increase (decrease) in interest expense related to unrecognized tax positions	$	(1,902	)	$	245		$	4,751
Net increase (decrease) in penalties related to unrecognized tax positions		(787	)		(3,039	)		12,022

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. 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. Taxing authorities in the various foreign locations in which we operate could apply one of the alternative transfer pricing methodologies which could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination.

Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include years 2003 to 2011. We are currently under audit in several of these jurisdictions. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial condition and cash flows.

U.S. Tax Jurisdiction. We are currently under audit by the Internal Revenue Service, or IRS, for the tax year 2010. In addition, during 2011, the IRS completed their audit of the tax year 2008 without any adjustment proposed by the auditors.

Brazil Tax Jurisdiction. The Brazilian tax authorities have audited our income tax returns for the years 2000, 2004, 2005 and 2007. In February 2012, the tax authorities concluded their audit of our income tax return for the 2007 tax year for which we received an assessment of R$35.1 million (approximately equal to USD $17 million at December 31, 2012) for income tax, including interest and penalties. We contested the assessment and, in the third quarter of 2012, a court in Brazil ruled to cancel the assessment. However, the Brazilian tax authorities have appealed the ruling. We have not accrued any tax expense related to this assessment.

In December 2009, we received an assessment of approximately $26.0 million for the years 2004 and 2005, including interest and penalty. We contested the tax assessment in January 2010 and are awaiting the outcome of the appeal. As required by GAAP, only the portion of the tax benefit that has a greater than 50% likelihood of being realized upon settlement is to be recognized. Consequently, we have accrued approximately $12.9 million of expense attributable to the portion of the tax assessment we determined to be an uncertain tax position, of which approximately $3.6 million is interest related and approximately $3.2 million is penalty related.

In addition, the tax auditors have issued an assessment for tax year 2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal.

During 2011, unrecognized tax benefits were reduced by approximately $6.8 million due to the lapse in the applicable statute of limitations for the 2006 tax year, of which $1.1 million was interest and $2.0 million was penalty.

Mexico Tax Jurisdiction. The Mexican tax authorities have audited our income tax returns for the years 2004 and 2006. The tax auditors have issued assessments for tax year 2004 of approximately $22.9 million, including interest and penalties, which we appealed. In August 2012, the Mexican tax authorities dismissed a claim against one of our Mexican subsidiaries and the 2004 tax year for that subsidiary is now closed. Consequently, during the third quarter of 2012, we reversed our $4.4 million accrual for this uncertain tax position, which included $0.2 million of penalty and $2.6 million of interest.

In January 2012, we received tax assessments for the tax year 2006 of approximately $24.4 million including interest and penalties. We have appealed the assessments.

Egypt Tax Jurisdiction. We are currently under audit by the Egyptian tax authorities for the tax years 2006 through 2010.

American Taxpayer Relief Act of 2012. The American Taxpayer Relief Act of 2012, or the Act, was signed into law on January 2, 2013. The Act extends through 2013 several expired or expiring temporary business provisions, commonly referred to as “extenders,” which are retroactively extended to the beginning of 2012. As required by GAAP, the effects of new legislation are recognized when signed into law. Consequently, we expect to reduce our first quarter 2013 tax expense by approximately $28 million as a result of recognizing the 2012 effect of the extenders.

14. Employee Benefit Plans

Defined Contribution Plans

We maintain defined contribution retirement plans for our U.S., United Kingdom, or U.K., and third-country national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the Internal Revenue Code of 1986, as amended, or the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During each year ended December 31, 2012, 2011 and 2010, we made a 4% profit-share contribution of participants’ defined compensation and matched up to 6% of each employee’s compensation contributed to the 401k Plan. Participants are fully vested in the employer match immediately upon enrollment in the 401k Plan and subject to a three year cliff vesting period for the profit sharing contribution. For the years ended December 31, 2012, 2011 and 2010, our provision for contributions was $25.9 million, $21.5 million and $23.8 million, respectively.

The defined contribution retirement plan for our U.K. employees provides that we make annual contributions in an amount equal to the employee’s contributions generally up to a maximum percentage of the employee’s defined compensation per year. For the years ended December 31, 2012, 2011 and 2010, our contribution for employees working in the U.K. sector of the North Sea was up to a maximum of 10%, 5.25% and 5.25%, respectively, of the employee’s defined compensation. For the years ended December 31, 2012, 2011 and 2010, our contribution for U.K. nationals working in the Norwegian sector of the North Sea was up to a maximum of 15%, 9.0% and 9.0%, respectively, of the employee’s defined compensation. Our provision for contributions was $2.7 million, $1.2 million and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During each year ended December 31, 2012, 2011 and 2010, we contributed 4% of participants’ defined compensation and matched up to 6% of each employee’s compensation contributed to the International Savings Plan. Our provision for contributions was $2.8 million, $2.9 million and $2.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Deferred Compensation and Supplemental Executive Retirement Plan

Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of our base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. Our provision for contributions to the Supplemental Plan for the years ended December 31, 2012, 2011 and 2010 was approximately $256,000, $245,000 and $238,000, respectively.

15. Segments and Geographic Area Analysis

Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue earnings process as it relates to the offshore drilling industry, over the operating lives of our drilling rigs.

Revenues from contract drilling services by equipment-type are listed below:


	Year Ended December 31,

	2012		2011		2010

	(In thousands)
Floaters:
Ultra-Deepwater	$	902,793	$	841,565	$	718,426
Deepwater		597,694		733,037		564,315
Mid-Water		1,275,068		1,482,032		1,678,793

Total Floaters		2,775,555		3,056,634		2,961,534
Jack-ups		160,511		197,534		267,983
Other		--		145		219

Total contract drilling revenues		2,936,066		3,254,313		3,229,736
Revenues related to reimbursable expenses		50,442		68,106		93,238

Total revenues	$	2,986,508	$	3,322,419	$	3,322,974

Geographic Areas

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At December 31, 2012, our actively-marketed drilling rigs were en route to or located offshore 12 countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.


	Year Ended December 31,

	2012		2011		2010

	(In thousands)
United States	$	173,961	$	323,381	$	635,545

International:
South America		1,427,927		1,736,798		1,308,641
Europe/Africa/Mediterranean		662,995		749,128		601,122
Australia/Asia		524,957		451,364		641,372
Mexico		196,668		61,748		136,294

		2,812,547		2,999,038		2,687,429


Total revenues	$	2,986,508	$	3,322,419	$	3,322,974

An individual international country may, from time to time, comprise a material percentage of our total contract drilling revenues from unaffiliated customers. For the years ended December 31, 2012, 2011 and 2010, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.


	Year Ended December 31,

	2012		2011		2010

Brazil		46.1%		49.4%		36.8%
United Kingdom		6.9%		4.6%		5.6%
Australia		6.7%		6.7%		10.0%
Mexico		6.6%		1.9%		4.1%
Angola		2.7%		9.6%		6.1%
Indonesia		2.4%		5.0%		1.3%

The following table presents our long-lived tangible assets by geographic location as of December 31, 2012, 2011 and 2010. A substantial portion of our assets is comprised of rigs that are mobile, and therefore asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods and may vary from period to period due to the relocation of rigs. In circumstances where our drilling rigs were in transit at the end of a calendar year, they have been presented in the tables below within the geographic area in which they were expected to operate.


	December 31,
	2012		2011		2010

	(In thousands)
Drilling and other property and equipment, net:
United States⁽¹⁾	$	444,984	$	283,049	$	638,529

International:
South America		1,827,247		1,979,303		2,290,412
Australia/Asia/Middle East ⁽²⁾		1,474,999		1,212,461		417,121
Europe/Africa/Mediterranean		799,194		852,300		897,998
Mexico		318,548		340,356		39,732

		4,419,988		4,384,420		3,645,263


Total	$	4,864,972	$	4,667,469	$	4,283,792

(1)

Long-lived tangible assets in the United States region as of December 31, 2012 and 2011 include $167.4 million and $14.6 million, respectively, in construction work-in-progress for the Ocean Onyx under construction in Brownsville, Texas.

(2)

Long-lived tangible assets in the Australia/Asia/Middle East region as of December 31, 2012 and 2011 include $823.6 million and $490.2 million, respectively, in construction work-in-progress for our drillships under construction in South Korea and the Ocean Apex under construction in Singapore.

The following table presents the countries in which material concentrations of our long-lived tangible assets were located as of December 31, 2012, 2011 and 2010:


	December 31,
	2012			2011			2010


Brazil		37.3	%		41.9	%		52.7%
South Korea ⁽¹⁾		15.2	%		10.5	%		--
United States ⁽²⁾		9.1	%		6.1	%		14.9%
Republic of Congo		7.4	%		--			9.3%
Indonesia		6.8	%		3.4	%		3.8%
Mexico		6.5	%		7.3	%		0.9%
Egypt		4.7	%		5.5	%		6.3%
Vietnam		1.4	%		6.6	%		0.6%
Angola		--			8.0	%		1.7%

(1)

Assets in South Korea, as of December 31, 2012 and 2011, include $741.1 million and $490.2 million, respectively, in construction work-in-progress for our drillships under construction.

(2)

Assets in the United States, as of December 31, 2012 and 2011, include $167.4 million and $14.6 million, respectively, in construction work-in-progress for the Ocean Onyx under construction in Brownsville, Texas.

As of December 31, 2012, 2011 and 2010, no other countries had more than a 5% concentration of our long-lived tangible assets.

Major Customers

Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the years ended December 31, 2012, 2011 and 2010 that contributed more than 10% of our total revenues are as follows:


	Year Ended December 31,
Customer	2012			2011			2010

Petróleo Brasileiro S.A.		33.3	%		35.0	%		23.7	%
OGX Petróleo e Gás Ltda.		12.5	%		14.1	%		14.1	%

16. Unaudited Quarterly Financial Data

Unaudited summarized financial data by quarter for the years ended December 31, 2012 and 2011 is shown below.


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per share data)

2012
Revenues	$	768,642	$	738,188	$	729,141	$	750,537
Operating income^(a)		265,410		257,184		244,822		194,962
Income before income tax expense		251,435		246,758		234,847		185,041
Net income		185,169		201,461		178,186		155,661
Net income per share:
Basic	$	1.33	$	1.45	$	1.28	$	1.12
Diluted	$	1.33	$	1.45	$	1.28	$	1.12

2011
Revenues	$	806,389	$	889,496	$	878,177	$	748,357
Operating income		319,265		367,596		350,277		218,276
Income before income tax expense		296,849		344,026		334,849		203,547
Net income ^(b)		250,612		266,586		256,854		188,490
Net income per share:
Basic	$	1.80	$	1.92	$	1.85	$	1.36
Diluted	$	1.80	$	1.92	$	1.85	$	1.36

(a)

Results for the fourth quarter of 2012 include a $62.4 million impairment charge related to rigs transferred to “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2012. See Note 1.

(b)

Results for the fourth quarter of 2011 reflect a reduction in income tax expense, primarily as a result of a year-end true up related to foreign taxes.

17. Subsequent Event

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.

Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2012. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2012.

Internal Control Over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment our management believes that, as of December 31, 2012, our internal control over financial reporting was effective based on those criteria to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Deloitte & Touche LLP, the registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our internal control over financial reporting. The attestation report of Deloitte & Touche LLP is included at the beginning of Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

Not applicable.

PART III

Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part III contained in our definitive proxy statement for our 2013 Annual Meeting of Stockholders, which is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

Item 11. Executive Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Item 14. Principal Accountant Fees and Services.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits


(1) Financial Statements	Page

Report of Independent Registered Public Accounting Firm		44
Consolidated Balance Sheets		46
Consolidated Statements of Operations		47
Consolidated Statements of Comprehensive Income		48
Consolidated Statements of Stockholders’ Equity		49
Consolidated Statements of Cash Flows		50
Notes to Consolidated Financial Statements		51

(2) Exhibit Index		82

See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit Index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 of Regulation S-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 21, 2013.


DIAMOND OFFSHORE DRILLING, INC.

By:		/S/ GARY T. KRENEK
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ LAWRENCE R. DICKERSON* Lawrence R. Dickerson	President, Chief Executive Officer and Director (Principal Executive Officer)	February 21, 2013

/s/ GARY T. KRENEK* Gary T. Krenek	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 21, 2013

/s/ BETH G. GORDON* Beth G. Gordon	Controller (Principal Accounting Officer)	February 21, 2013

/s/ JAMES S. TISCH* James S. Tisch	Chairman of the Board	February 21, 2013

/s/ JOHN R. BOLTON* John R. Bolton	Director	February 21, 2013

/s/ CHARLES L. FABRIKANT* Charles L. Fabrikant	Director	February 21, 2013

/s/ PAUL G. GAFFNEY II* Paul G. Gaffney II	Director	February 21, 2013

/s/ EDWARD GREBOW* Edward Grebow	Director	February 21, 2013

/s/ HERBERT C. HOFMANN* Herbert C. Hofmann	Director	February 21, 2013

/s/ CLIFFORD M. SOBEL* Clifford M. Sobel	Director	February 21, 2013

/s/ ANDREW H. TISCH* Andrew H. Tisch	Director	February 21, 2013

/s/ RAYMOND S. TROUBH* Raymond S. Troubh	Director	February 21, 2013

*By:

/s/ WILLIAM C. LONG

William C. Long

Attorney-in-fact

EXHIBIT INDEX


Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003) (SEC File No. 1-13926).

3.2		Amended and Restated By-laws (as amended through March 15, 2011) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed March 16, 2011).

4.1		Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

4.2		Fourth Supplemental Indenture, dated as of August 27, 2004, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed September 1, 2004) (SEC File No. 1-13926).

4.3		Fifth Supplemental Indenture, dated as of June 14, 2005, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to JPMorgan Chase Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed June 16, 2005) (SEC File No. 1-13926).

4.4		Sixth Supplemental Indenture, dated as of May 4, 2009, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed May 4, 2009).

4.5		Seventh Supplemental Indenture, dated as of October 8, 2009, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 8, 2009).

10.1		Registration Rights Agreement (the “Registration Rights Agreement”) dated October 16, 1995 between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.2		Amendment to the Registration Rights Agreement, dated September 16, 1997, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.3		Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).

10.4+		Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).

10.5+		Diamond Offshore Management Bonus Program, as amended and restated, and dated as of December 31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).

10.6+		Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2007) (SEC File No. 1-13926).

10.7+		Form of Stock Option Certificate for grants to executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926).


10.8+		Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926).

10.9+		The Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (Amended and Restated as of March 20, 2012) (incorporated by reference to Exhibit A attached to our definitive proxy statement on Schedule 14A filed March 29, 2012).

10.10+		Form of Award Certificate for stock appreciation right grants to the Company’s executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006) (SEC File No. 1-13926).

10.11+		Form of Award Certificate for stock appreciation right grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007) (SEC File No. 1-13926).

10.12+		Employment Agreement between Diamond Offshore Management Company and Lawrence R. Dickerson dated as of December 15, 2006 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 21, 2006) (SEC File No. 1-13926).

10.13+		Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek dated as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed December 21, 2006) (SEC File No. 1-13926).

10.14+		Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).

10.15+		Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006 (incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).

10.16+		Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).

10.17+		Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006) (SEC File No. 1-13926).

10.18+		Amendment to Employment Agreement, dated June 16, 2008, between Diamond Offshore Management Company and Lawrence R. Dickerson (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008).

10.19		5-Year Revolving Credit Agreement, dated as of September 28, 2012, among Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association, as administrative agent and swingline lender, the issuing banks named therein and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 1, 2012).

12.1*		Statement re Computation of Ratios.

21.1*		List of Subsidiaries of Diamond Offshore Drilling, Inc.

23.1*		Consent of Deloitte & Touche LLP.


24.1*		Powers of Attorney.

31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.

31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.

32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Calculation Linkbase Document.

101.LAB**		XBRL Taxonomy Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.

101.DEF**		XBRL Taxonomy Extension Definition.

		* Filed or furnished herewith.
		** The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections.
		+ Management contracts or compensatory plans or arrangements.