DIAMOND OFFSHORE DRILLING INC
Item 1. Business.
General
Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a fleet of 49 offshore rigs, consisting of 32 semisubmersibles, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. See “ - Fleet Enhancements and Additions.” Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.
Our Fleet
Our diverse fleet enables us to offer a broad range of services worldwide in both the floater market (ultra-deepwater, deepwater and mid-water) and the non-floater, or jack-up, market.
Floaters. A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic positioning, or DP, to keep the rig on location, or with anchors tethered to the sea bed. While DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats, while non-DP, or moored, semisubmersibles require tug boats or the use of a heavy lift vessel to move between locations.
A drillship is an adaptation of a maritime vessel which is designed and constructed to carry out drilling operations by means of a substructure with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drillsite through the use of either an anchoring system or a dynamic-positioning system similar to those used on semisubmersible rigs.
Our floater fleet (semisubmersibles and drillships) can be further categorized based on the nominal water depth for each class of rig as follows:
Category
Nominal Water Depth (a)
(in feet)
Number of Units in Our Fleet
Ultra-Deepwater
7,501 to 12,000
11 (b)
Deepwater
5,000 to 7,500
6 (c)
Mid-Water
400 to 4,999
(a) Nominal water depth for semisubmersibles and drillships reflects the current operating water depth capability for each drilling unit. 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). On a case by case basis, we may achieve even greater depth capacity by providing additional equipment.
(b) Includes three drillships under construction.
(c) Includes the Ocean Onyx to be constructed utilizing the hull of one of our existing mid-water floaters.
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 rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite. Most of our jack-up rigs are equipped with a cantilever system that enables the rig to cantilever or extend its drilling package over the aft end of the rig.
Fleet Enhancements and Additions. Our long-term strategy is to upgrade our fleet to meet customer demand for advanced, efficient and high-tech rigs by acquiring or building new rigs when possible to do so at attractive prices, and otherwise by enhancing the capabilities of our existing rigs at a lower cost and reduced construction period than newbuild construction would require. Since December 2010, we have entered into three separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of three dynamically positioned, ultra-deepwater drillships with deliveries scheduled for the second and fourth quarters of 2013 and the second quarter of 2014. We expect the aggregate cost for the three drillships, including commissioning, spares and project management, to be approximately $1.8 billion.
During 2009, we acquired two new-build ultra-deepwater, dynamically positioned, semisubmersible drilling rigs, the Ocean Courage and the Ocean Valor. Including our rig acquisitions in 2009 and our three drillships on order, we have purchased, ordered or upgraded eight units with capabilities in nominal water depths of 10,000 feet over the last five years.
In January 2012, we announced the construction of a moored semisubmersible rig that will be designed to operate in water depths up to 6,000 feet. The rig, to be named the Ocean Onyx, will be constructed utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Voyager. The rig will be constructed in Brownsville, Texas and is expected to be delivered in the third quarter of 2013 at an aggregate cost of approximately $300 million, including commissioning, spares and project management costs.
We will evaluate further rig acquisition and upgrade opportunities as they arise. However, we can provide no assurance whether, or to what extent, we will continue to make rig acquisitions or upgrades to our fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Requirements” in Item 7 of this report.
See “ - Fleet Status” for more detailed information about our drilling fleet as of January 30, 2012.
Fleet Status
The following table presents additional information regarding our floater fleet at January 30, 2012:
Type and Name
Nominal
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
Brazil
Petrobras
Ocean Courage
10,000
DP; 6R; 15K; 4M
Brazil
Petrobras
Ocean Confidence
10,000
DP; 6R; 15K; 4M
Angola
Cobalt
Ocean Monarch
10,000
15K; 4M
Vietnam
TNK Vietnam
Ocean Endeavor
10,000
15K; 4M
Egypt
Burullus
Ocean Rover
8,000
15K; 4M
Malaysia
Murphy Exploration
Ocean Baroness
8,000
15K; 4M
Brazil
Petrobras
Ultra-Deepwater Drillships (4):
Ocean BlackHawk
10,000
DP; 7R; 15K; 5M
Q2 2013
South Korea
Under construction/Anadarko (d)
Ocean BlackHornet
10,000
DP; 7R; 15K; 5M
Q4 2013
South Korea
Under construction/Anadarko (d)
Ocean BlackRhino
10,000
DP; 7R; 15K; 5M
Q2 2014
South Korea
Under construction
Ocean Clipper
7,875
DP; 15K
Brazil
Petrobras
Deepwater Semisubmersibles (6)
Ocean Onyx
6,000
15K
Q3 2013
GOM shipyard
Under construction (e)
Ocean Victory
5,500
15K
GOM
Walter Oil & Gas
Ocean America
5,500
15K
Australia
Woodside
Ocean Valiant
5,500
15K
Equatorial Guinea
Hess
Ocean Star
5,500
15K
Brazil
Perenco
Ocean Alliance
5,250
DP; 15K
Brazil
Petrobras
Mid-Water Semisubmersibles (19):
Ocean Winner
4,000
Brazil
Petrobras
Ocean Worker
4,000
Brazil
Petrobras
Ocean Quest
4,000
15K
Brazil
OGX
Ocean Yatzy
3,300
DP
Brazil
Petrobras
Ocean Patriot
3,000
15K
Australia
PTTEP
Ocean Epoch
3,000
Malaysia
Cold stacked
Ocean General
3,000
Malaysia
Actively marketing
Ocean Yorktown
2,850
Mexico
PEMEX
Ocean Concord
2,300
Brazil
Petrobras
Ocean Lexington
2,200
Brazil
OGX
Ocean Saratoga
2,200
Guyana
CGX Energy
Ocean Whittington
1,650
Brazil
Petrobras
Ocean Bounty
1,500
Malaysia
Cold stacked
Ocean Guardian
1,500
15K
In transit: North Sea/U.K.
DODI/Shell
Ocean New Era
1,500
GOM
Cold stacked
Ocean Princess
1,500
15K
North Sea/U.K.
Enquest
Ocean Vanguard
1,500
15K
North Sea/Norway
Statoil
Ocean Nomad
1,200
North Sea/U.K.
B G International
Ocean Ambassador
1,100
Brazil
OGX
Attributes
DP = Dynamically Positioned/Self-Propelled
7R = Seven ram blow out preventer
4M = Four Mud Pumps
6R = Six ram blow out preventer
15K = 15,000 psi well control system
5M = Five Mud Pumps
(a) Represents year rig was (or is expected to be) built and originally placed in service or year 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) Drillship is contracted for future work upon completion of commissioning; unit is currently expected to commence drilling operations in the GOM.
(e) To be constructed utilizing the hull of an existing mid-water unit, which previously operated as the Ocean Voyager.
The following table presents additional information regarding our jack-up fleet at January 30, 2012:
Type and Name
Nominal Water
Depth (a)
(in feet)
Attributes
Year Built
Current Location (b)
Customer (c)
Jack-ups (13):
Ocean Scepter
IC; 15K
Mexico
PEMEX
Ocean Titan
IC; 15K
Mexico
PEMEX
Ocean King
IC
Montenegro
Actively marketing
Ocean Nugget
IC
Mexico
PEMEX
Ocean Summit
IC
Mexico
PEMEX
Ocean Heritage
IC
Egypt
Warm stacked
Ocean Spartan
IC
GOM
Cold stacked
Ocean Spur
IC
Egypt
WEPCO
Ocean Sovereign
IC
Malaysia
Cold stacked
Ocean Champion
MS
GOM
Cold stacked
Ocean Columbia
IC
GOM
Walter Oil & Gas
Ocean Crusader
MC
GOM
Cold stacked
Ocean Drake
MC
GOM
Cold stacked
Attributes
IC = Independent-Leg Cantilevered Rig
MS = Mat-Supported Slot Rig
15K = 15,000 psi well control system
MC = Mat-Supported Cantilevered Rig
(a) Nominal 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.
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 segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.
Offshore Contract Drilling Services
Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through a competitive bid process, although it is not unusual for us to be awarded drilling contracts following direct negotiations. Our drilling contracts generally provide for a basic fixed dayrate regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for reductions in rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate contracts may also provide for the ability to earn an incentive bonus from our customer based upon performance.
The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, in what we refer to as a well-to-well contract, or a fixed period of time, in what we refer to as a term contract. Many drilling contracts may be terminated by the customer in the event the drilling unit is destroyed or lost, or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to events beyond the control of either party to the contract. Certain of our contracts also permit the customer to terminate the contract early by giving notice; in most circumstances, this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. See “Risk Factors - Our business involves numerous operating hazards which could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us,” “Risk Factors - The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market,” “Risk Factors - Our drilling contracts may be terminated due to events beyond our control” and “Risk Factors - We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico” in
Item 1A. Risk Factors.
Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that we currently believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.
Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.
Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since our customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for our rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond our control, including:
•
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 in the United States and elsewhere;
•
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 drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.
In the aftermath of the Macondo well blowout in April 2010 and the subsequent investigation into the causes of the event, new rules for oil and gas operations on the Outer Continental Shelf, or OCS, have been implemented, including new standards for well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations may continue to be
announced, including rules regarding employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. We are not able to predict the likelihood, nature or extent of additional rulemaking, nor are we able to predict the future impact of these events on our operations. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers could reduce exploration activity in the GOM and therefore demand for our services.
Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.
As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. In addition, new laws or regulations, including those that may come into effect following the Macondo incident, may require an increase in our capital spending for additional equipment to comply with such requirements and could also result in a reduction in revenues associated with downtime required to install such equipment.
Our business involves numerous operating hazards which could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. Any of the foregoing events could result in significant damage or loss to our properties and assets, significant loss of revenues, and significant damage claims against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Consistent with industry practice, our contracts with our customers generally contain contractual rights to indemnity from our customer for, among other things, pollution originating from the well, while we retain responsibility for pollution originating from the rig. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by us, our subcontractors and/or suppliers and our customers may dispute, or be unable to meet, their contractual indemnification obligations to us.
We maintain liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Moreover, insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all. Accordingly, it is possible that our losses from the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.
We believe that the policy limit under our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. However, if an accident or other event occurs that exceeds our coverage limits or is not an insurable event under our insurance policies, or is not
fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial position and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all of these risks. In addition, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.
Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.
Compliance with or breach of environmental laws can be costly and could limit our operations.
In the United States and in many of the international locations in which we operate, regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time they were performed.
The United States Oil Pollution Act of 1990, or OPA ’90, and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ’90 and such similar legislation and related regulations impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. OPA ’90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages.
The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations and cash flows.
Our industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.
Our industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. We cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. In response to a contraction in demand for certain types of our drilling rigs, primarily our shallow water jack-up rigs, we have cold stacked eight rigs as of the date of this report. We also may be required to idle additional rigs or to enter into lower rate contracts. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
Significant new rig construction and upgrades of existing drilling units could also intensify price competition. As of the date of this report, based on analyst reports, we believe that there are approximately 77 jack-up rigs and 96 floaters on order and scheduled for delivery between 2012 and 2018, with approximately half of these rigs scheduled for delivery in the next two years. The resulting increases in rig supply could be sufficient to depress rig utilization and intensify price competition from both existing competitors, as well as new entrants into the offshore drilling market. As of the date of this report, not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. The majority of the floaters
on order are dynamically positioned drilling units, which further increases competition with our fleet in certain circumstances, depending on customer requirements. In Brazil, Petrobras, which accounted for approximately 35% of our consolidated revenues in 2011 and, as of February 1, 2012, accounted for approximately $3.7 billion of our contract drilling backlog through 2016 and to which ten of our floaters are currently contracted, has announced plans to construct locally 33 new deepwater drilling units to be delivered beginning in 2015. These new drilling units would increase rig supply and could intensify price competition in Brazil as well as other markets as they enter the market, would compete with, and could displace, our deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect our utilization rates, particularly in Brazil.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
As of the date of this report, our contract drilling backlog was approximately $8.6 billion for contracted future work extending, in some cases, until 2019. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability to fulfill their contractual commitments to us may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview - Contract Drilling Backlog” included in Item 7 of this report.
We rely heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on our financial results.
We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. In 2011, our five largest customers in the aggregate accounted for 62% of our consolidated revenues. We expect Petrobras and OGX, which accounted for approximately 35% and 14% of our consolidated revenues in 2011, respectively, to continue to be significant customers in 2012. Our contract drilling backlog, as of the date of this report, includes $1.3 billion, or 51% of our total contracted backlog for 2012, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil. While it is normal for our customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview - Contract Drilling Backlog” included in Item 7 of this report.
The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market.
The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit our profitability.
Contracts for our drilling units are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.
Our contracts for our drilling units provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by us. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond our control. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers. Our inability to recover these increased or unforeseen costs from our customers could materially and adversely affect our financial position, results of operations and cash flows.
Our drilling contracts may be terminated due to events beyond our control.
Our customers may terminate some of our term drilling contracts if the drilling unit is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows. During periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets and the economic downturn. If our customers cancel some of their contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could materially and adversely affect our financial position, results of operations or cash flows.
A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations.
We operate in various regions throughout the world which may expose us to political and other uncertainties, including risks of:
•
terrorist acts, war and civil disturbances;
•
piracy or assaults on property or personnel;
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kidnapping of personnel;
•
expropriation of property or equipment;
•
renegotiation or nullification of existing contracts;
•
changing political conditions;
•
foreign and domestic monetary policies;
•
the inability to repatriate income or capital;
•
difficulties in collecting accounts receivable and longer collection periods;
•
fluctuations in currency exchange rates;
•
regulatory or financial requirements to comply with foreign bureaucratic actions;
•
travel limitations or operational problems caused by public health threats; and
•
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:
•
the equipping and operation of drilling units;
•
import-export quotas or other trade barriers;
•
repatriation of foreign earnings or capital;
•
oil and gas exploration and development;
•
taxation of offshore earnings and earnings of expatriate personnel; and
•
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.
As of the date of this report, the greatest concentration of our operating assets outside the United States was offshore Brazil, where we had 14 rigs in our fleet either currently working or contracted to work during 2012.
We may enter into drilling contracts that expose us to greater risks than we normally assume.
From time to time, we may enter into drilling contracts with national oil companies, government-controlled entities or others that expose us to greater risks than we normally assume, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to us, or if a termination payment is required, it may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows. For example, we currently operate, and expect to continue to operate, our drilling rigs offshore Mexico for PEMEX - Exploración y Producción, or PEMEX, the national oil company of Mexico. The terms of these contracts expose us to greater environmental liability than we normally assume, and provide that, among other things, each contract can be terminated by PEMEX on short notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a material negative impact on our future operations or financial results.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
Due to our international operations, we have experienced currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not effectively hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.
Changes in laws, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results.
Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our worldwide operations through various subsidiaries in a number of different jurisdictions. We are subject to the tax laws, tax regulations and income tax treaties within and between the countries in which we operate as well as countries in which we may be resident. We determine our income tax expense based on our interpretation of the applicable tax laws and regulations in effect in each jurisdiction for the period during which we operate and earn income. Our overall effective tax rate could be adversely and suddenly affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax law, tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate.
Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any tax position taken, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our operations, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.
We may be required to accrue additional tax liability on certain of our foreign earnings.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. We do not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes that, if material, could have a material adverse effect on our financial position, results of operations and cash flows.
Acts of terrorism and other political and military events could adversely affect the markets for our drilling services.
Terrorist attacks and the continued threat of terrorism in the U.S. and abroad, the continuation or escalation of existing armed hostilities or the outbreak of additional hostilities could lead to increased political, economic and financial market instability and a downturn in the economies of the U.S. and other countries. A lower level of economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices, either of which could materially and adversely affect the market for our offshore drilling services, our dayrates or utilization and, accordingly, our financial position, results of operations and cash flows. While we take steps that we believe are appropriate to secure our energy assets, there is no assurance that we can completely secure these assets, completely protect them against a terrorist attack or other political and military events or obtain adequate insurance coverage for such events at reasonable rates.
We may be subject to litigation that could have a material adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have a material adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.
Failure to obtain and retain highly skilled personnel could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our business. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including due to the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could adversely affect our results of operations. As of the date of this report, we have three new ultra-deepwater drillships under construction which will require additional skilled personnel to operate. In addition, additional new capacity in the offshore drilling market could cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. The heightened competition for skilled personnel could materially and adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.
Although we have paid special cash dividends in the past, we may not pay special cash dividends in the future and we can give no assurance as to the amount or timing of the payment of any future special cash dividends.
We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant at that time. Moreover, our dividend policy may change from time to time. We cannot assure you that we will continue to declare any special cash dividends at all or in any particular amounts. If in the future we pay special cash dividends less frequently or in smaller amounts, or cease to pay any special cash dividends, it could have a negative effect on the market price of our common stock. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Dividend Policy” included in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Sources of Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Historical Cash Flows” included in Item 7 of this report.
Rig conversions, upgrades or new-builds may be subject to delays and cost overruns.
From time to time we may undertake to add new capacity through conversions or upgrades to our existing rigs or through new construction, such as our three new, ultra-deepwater drillships under construction and our construction of the Ocean Onyx. Projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:
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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;
•
difficulties in obtaining necessary permits or in meeting permit conditions;
•
design and engineering problems;
•
customer acceptance delays;
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shipyard failures or unavailability; and
•
failure or delay of third party service providers 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 position, results of operations and cash flows.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2011, we had $1.5 billion in long-term debt. Our ability to meet our debt service obligations is dependent upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our debt levels and the terms of our indebtedness could potentially limit our liquidity and flexibility in obtaining additional financing, at rates which we consider reasonable or at all, and, thus, could limit our ability to pursue other business opportunities. In addition, our overall debt level and/or market conditions could lead the credit rating agencies to lower our corporate credit ratings. A downgrade in our corporate credit ratings could impact our ability to issue additional debt by raising the cost of issuing new debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. This could limit our ability to pursue other business opportunities.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
Loews Corporation, which we refer to as Loews, beneficially owned approximately 50.4% of our outstanding shares of common stock as of February 16, 2012 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.
Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial Corporation, a 90% owned subsidiary engaged in commercial property and casualty insurance; HighMount Exploration & Production LLC, a wholly owned subsidiary engaged in exploration, production and marketing of natural gas and natural gas liquids; Boardwalk Pipeline Partners, LP, a 61% owned subsidiary engaged in the operation of interstate natural gas transmission pipeline systems; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation of hotels. It is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.
Item 1B. Unresolved Staff Comments.
Not applicable.
Item 2. Properties.
We own an eight-story office building totaling 170,000 square feet on 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located. We also own two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations, two buildings totaling 77,200 square feet and 11 acres of land in Macae, Brazil, for our South American operations and two buildings totaling 21,000 square feet and two acres of land in Ciudad del Carmen, Mexico, for our Mexican operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Indonesia, Norway, Malaysia, Singapore, Egypt, Equatorial Guinea, Angola, Vietnam and the U.K. to support our offshore drilling operations.
Item 3. Legal Proceedings.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Price Range of Common Stock
Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common stock as reported by the NYSE.
As of February 16, 2012 there were approximately 203 holders of record of our common stock. This number represents registered stockholders and does not include stockholders who hold their shares institutionally.
Dividend Policy
In 2011, we paid regular cash dividends of $0.125 and special cash dividends of $0.75 per share of our common stock on February 28, June 1, September 1 and December 1. In 2010, we paid regular cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1. We also paid special cash dividends in 2010 of $1.875 per share of our common stock on March 1, $1.375 per share of our common stock on June 1, and $0.75 per share of our common stock on September 1 and December 1.
On February 1, 2012, we declared a regular cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the regular and special cash dividends are payable on March 1, 2012 to stockholders of record on February 13, 2012.
We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant at that time.
CUMULATIVE TOTAL STOCKHOLDER RETURN
The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index, a Peer Group Index and the Dow Jones U.S. Oil Equipment & Services over the five year period ended December 31, 2011.
Comparison of 2007 - 2011 Cumulative Total Return (1)
(1) Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2006 in our common stock, the two published indices and a peer group index.
Our dividend history for the periods reported above is as follows:
Q1
Q2
Q3
Q4
Year
Regular
Special
Regular
Special
Regular
Special
Regular
Special
$ 0.125
$ 0.75
$ 0.125
$ 0.75
$ 0.125
$ 0.75
$ 0.125
$ 0.75
$ 0.125
$ 1.875
$ 0.125
$ 1.375
$ 0.125
$ 0.75
$ 0.125
$ 0.75
$ 0.125
$ 1.875
$ 0.125
$ 1.875
$ 0.125
$1.875
$ 0.125
$ 1.875
$ 0.125
$ 1.25
$ 0.125
$ 1.25
$ 0.125
$ 1.25
$ 0.125
$ 1.875
$ 0.125
$ 4.00
$ 0.125
-
$ 0.125
-
$ 0.125
$ 1.25
(2) We have added the Dow Jones U.S. Oil Equipment & Services index to replace our peer group index. This index represents the oil equipment and services subsector, as defined by Dow Jones indexes, and measures the performance of U.S. companies in this sector.
(3) The cumulative stockholder return for our peer group index, comprised of Ensco plc, Noble Corporation, Rowan Companies, Inc. and Transocean Ltd, has been presented to compare our total return with both the newly selected index and the peer group index used in the immediately preceding year. Pride International, Inc. is not included in our peer group index due to its 2010 merger with Ensco plc.
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. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
We provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling. Our fleet of 49 offshore drilling rigs consists of 32 semisubmersibles, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. In addition, in January 2012, we announced the construction of a moored semisubmersible rig that will be designed to operate in water depths up to 6,000 feet. The rig, to be named the Ocean Onyx, will be constructed utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Voyager.
Of our fleet, eight rigs are currently cold stacked, consisting of three intermediate semisubmersibles (one in the U.S. Gulf of Mexico, or GOM, and two in Malaysia) and five jack-up rigs (four in the GOM and one in Malaysia).
Overview
International Floater Market
Our floating rigs accounted for approximately 94% of our contract drilling revenue during the 2011. As of the date of this report, industry-wide floater utilization is reported to be greater than 90%, and, as of February 1, 2012, our floating rigs were committed for approximately 75% of the days remaining in 2012 and 54% of 2013.
Internationally, the ultra-deepwater and deepwater floater markets are generally strong and also show signs of further strengthening, particularly in the ultra-deepwater segment where we believe that there are few uncontracted rigs available to work in 2012. However, based on a December 2011 analyst report, there are 49 ultra-deepwater and deepwater floaters under construction, which are expected to enter the market in 2012 and 2013. Many of these floaters, primarily those scheduled for delivery in 2013, are not yet contracted for future work.
Market strength for ultra-deepwater and deepwater rigs varies among geographic regions. Upcoming drilling programs offshore Brazil will require a number of additional ultra-deepwater rigs. This demand may be met by rigs contructed domestically in Brazil, including 33 deepwater floaters ordered by Petrobras. However, additional demand for ultra-deepwater rigs could develop if Brazilian drilling programs, including those of Petrobras, are accelerated prior to delivery of domestically-constructed rigs. In addition, successful exploration and development programs in West Africa have given rise to a robust market for deepwater and ultra-deepwater rigs in that region.
Market strength for mid-water floaters is stable or improving depending on the geographic market. In the North Sea, the mid-water market is strong, with signs of increasing dayrates, and, in the Mediterranean region, demand remains solid. The Southeast Asia and Australia markets also remain steady.
Worldwide Jack-up Market
Four of our marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Of our two remaining marketed international jack-ups, one is currently working in Egypt, and the other, located in Montenegro, is actively seeking work.
GOM Floater and Jack-up Market
Deepwater drilling activity in the GOM, while strengthening, continues to be impacted by the issuance of oil and gas drilling permits for operations on the OCS, which has not yet returned to pre-Macondo levels. In addition, since the Macondo well blowout in 2010 more stringent and encompassing rules for oil and gas operations on the OCS have been implemented. As of the date of this report, we have two actively marketed rigs in the GOM, consisting of one semisubmersible and one jack-up rig. The Ocean Victory and Ocean Columbia are currently operating in the GOM, both with contract backlog extending into the second quarter of 2012. The construction of our deepwater, moored semisubmersible rig, the Ocean Onyx, is taking place in a shipyard in Brownsville, Texas.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of February 1, 2012, October 17, 2011 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011) and February 1, 2011 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2010). Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.
(1) Contract drilling backlog as of February 1, 2012 for our ultra-deepwater floaters includes (i) $1.9 billion attributable to our contracted operations offshore Brazil for the years 2012 to 2015 and (ii) $1.8 billion attributable to future work for two of our drillships under construction.
(2) Contract drilling backlog as of February 1, 2012 for our deepwater floaters includes $787.0 million attributable to our contracted operations offshore Brazil for the years 2012 to 2016.
(3) Contract drilling backlog as of February 1, 2012 for our mid-water floaters includes $1.6 billion attributable to our contracted operations offshore Brazil for the years 2012 to 2015.
The following table reflects the amount of our contract drilling backlog by year as of February 1, 2012.
(1) Contract drilling backlog as of February 1, 2012 for our ultra-deepwater floaters includes (i) $507.0 million, $524.0 million, $524.0 million and $324.0 million for the years 2012 to 2015, respectively, attributable to our contracted operations offshore Brazil and (ii) $29.0 million and $299.0 million for the years 2013 and 2014, respectively, and $1.5 billion in the aggregate for the years 2015 to 2019, attributable to future work for two of our drillships under construction.
(2) Contract drilling backlog as of February 1, 2012 for our deepwater floaters includes (i) $220.0 million, $222.0 million and $149.0 million for the years 2012 to 2014, respectively, and $196.0 million in the aggregate for the years 2015 to 2016, attributable to our contracted operations offshore Brazil.
(3) Contract drilling backlog as of February 1, 2012 for our mid-water floaters includes (i) $631.0 million, $477.0 million, $368.0 million and $86.0 million for the years 2012 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, 2012. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning dates for the Ocean BlackHawk, Ocean BlackHornet, Ocean BlackRhino and the Ocean Onyx, which are all under construction.
(1) As of February 1, 2012, includes approximately 1,100 and 500 currently known, scheduled shipyard, survey and mobilization days for 2012 and 2013, respectively.
General
The two most significant variables affecting our revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political, regulatory and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.
Demand affects the number of days our fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.
We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.
From time to time, we may receive fees from our customers for capital improvements to our rigs (either lump-sum or dayrate). We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.
As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, we expect contract drilling revenue in 2012 to decline from the levels attained in 2011. We also expect contract drilling revenue for some of our rigs to be lower as these rigs fulfill term commitments under contracts at lower dayrates than previously earned in 2011 and may not be able to benefit from higher dayrates that the market is currently bearing. See “Risk Factors - The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market” in Item 1A of this report.
We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.
Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs associated with training new and seasoned employees can be significant. We expect our labor and training costs to increase in 2012 as a result of increased hiring and training activities as we continue the process of crewing three new drillships. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment and the regions in which our rigs are working.
Our operating costs are also impacted by the regulatory environments in which we operate. The adoption of new regulations could result in additional inspection and certification costs, as well as require additional capital investment to comply with regulatory requirements. Accordingly, we cannot fully predict the financial impact of any new regulations that may arise relating to drilling activities in the GOM, or elsewhere in the world. New laws or regulations may require an increase in our capital spending for additional equipment to comply with such requirements. Our business could be negatively impacted by additional downtime which may be required to obtain necessary equipment and to install such equipment or to obtain the required inspections or certifications as prescribed under such regulations.
Operating expenses generally are not affected by changes in dayrates, and short-term reductions in utilization do not necessarily result in lower operating expenses. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm stacked” state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, as incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods following capital upgrades.
Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these special surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.
In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the U.K. and Norwegian sectors of the North Sea.
During 2012, 11 of our rigs will require 5-year surveys and one of our U.K. rigs will require dry-docking for inspections. We expect these 12 rigs to be out of service for approximately 660 days in the aggregate. We also expect to spend an additional approximately 440 days during 2012 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ - Overview - Contract Drilling Backlog.”
We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows. Under our insurance policy that expires on May 1, 2012, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.
In addition, under our insurance policy that expires on May 1, 2012, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage, including for personal injury claims, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under the current policy commences on May 1 of each year.
Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. For the year ended December 31, 2011, we capitalized interest of $11.2 million on qualifying expenditures related to the construction of our three new drillships, beginning in August 2011. In addition, during 2012, we also expect to capitalize interest related to the construction of the Ocean Onyx.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:
Property, Plant and Equipment. We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the years ended December 31, 2011 and 2010, we capitalized $269.5 million and $379.8 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $50 million per project.
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as cold stacking a rig or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
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dayrate by rig;
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utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
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the per day operating cost for each rig if active, warm stacked or cold-stacked;
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the estimated annual cost for rig replacements and/or enhancement programs;
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the estimated maintenance, inspection or other costs associated with a rig returning to work;
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salvage value for each rig; and
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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.
A summary of our cold stacked rigs evaluated for impairment at December 31, 2011, 2010 and 2009 was as follows:
We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these eight, seven and four rigs were not subject to impairment at December 31, 2011, 2010 and 2009, respectively.
Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.
Personal Injury Claims. Our deductibles for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models.
The models used in estimating our aggregate reserve for personal injury claims include actuarial assumptions such as:
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claim emergence, or the delay between occurrence and recording of claims;
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settlement patterns, or the rates at which claims are closed;
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development patterns, or the rate at which known cases develop to their ultimate level;
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average, potential frequency and severity of claims; and
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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:
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the severity of personal injuries claimed;
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significant changes in the volume of personal injury claims;
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the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
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inconsistent court decisions; and
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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 $1.7 billion of undistributed foreign earnings and profits. Although we do not intend to repatriate the earnings of DOIL and have not provided U.S. income taxes for such earnings, except to the extent that such earnings were immediately subject to U.S. income taxes, these earnings could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practicable to estimate this potential liability.
In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment, and utilize outside consultants to assist us in the development of such transfer pricing methodologies. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts.
We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense.
Results of Operations
Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.
Key performance indicators by equipment type are listed below.
(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) 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).
(3) 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, 2011, 2010 and 2009
The following is a summary of the most significant transfers of our rigs during 2009, 2010 and 2011 between the geographic areas in which we operate:
Rig
Rig Type
Relocation Details
Date
Floaters:
Ocean Monarch
Ultra-Deepwater
Completion of major upgrade and relocation from Singapore shipyard to GOM
March 2009
Ocean Baroness
Ultra-Deepwater
GOM to Brazil
March 2010
Ocean Courage
Ultra-Deepwater
GOM to Brazil
March 2010
Ocean Valor
Ultra-Deepwater
Completion of construction and relocation from 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 Valiant
Deepwater
GOM to Angola
July 2009
Ocean Star
Deepwater
GOM to Brazil
January 2010
Ocean America
Deepwater
GOM to Australia
March 2010
Ocean Quest
Mid-Water
GOM to Brazil
February 2009
Ocean Ambassador
Mid-Water
GOM to Brazil
June 2009
Ocean Bounty
Mid-Water
Cold stacked (Malaysia)
July 2009
Ocean Lexington
Mid-Water
Egypt to Brazil
September 2009
Ocean Guardian
Mid-Water
North Sea to the Falkland Islands
November 2009
Ocean Voyager
Mid-Water
Mexico to GOM (cold stacked June 2010)
March 2010
Ocean New Era
Mid-Water
Mexico to GOM (cold stacked September 2010)
August 2010
Ocean Epoch
Mid-Water
Cold stacked (Malaysia)
February 2011
Ocean Yorktown
Mid-Water
Brazil to GOM
August 2011
Ocean Yorktown
Mid-Water
GOM to Mexico
December 2011
Jack-ups:
Ocean Champion
Jack-up
Cold stacked (GOM)
June 2009
Ocean Crusader
Jack-up
Cold stacked (GOM)
June 2009
Ocean Drake
Jack-up
Cold stacked (GOM)
June 2009
Ocean Summit
Jack-up
GOM to Mexico
July 2009
Ocean Columbia
Jack-up
Mexico to GOM
November 2009
Ocean Scepter
Jack-up
Argentina to GOM
December 2009
Ocean Shield
Jack-up
Sold
July 2010
Ocean Scepter
Jack-up
GOM to Brazil
August 2010
Ocean Spartan
Jack-up
Cold stacked (GOM)
September 2010
Ocean Sovereign
Jack-up
Cold stacked (Malaysia)
October 2011
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
Overview
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. Our two newest floaters, 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, reflecting 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:
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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.
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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. 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 the current year is 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. 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.
Also contributing to our lower effective tax rate in 2011, compared to the prior year, was the impact of a tax law provision that expired at the end of 2009 but was subsequently signed back into law in December 2010. This provision allows 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 now plan to reinvest these earnings internationally, and consequently, we are no longer providing 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.
2010 Compared to 2009
Operating Income. Operating income in 2010 decreased $477.8 million, or 25%, compared to 2009. Our operating results were negatively impacted by a decline in average daily revenue earned by our rigs in 2010 from the levels attained in 2009. While our contracted revenue backlog enabled us to partially mitigate the impact of the weakened market conditions at the time, our total contract drilling revenue decreased $306.8 million, or 9%, compared to 2009. Revenue generated by our floater fleet decreased an aggregate $117.8 million, or 4%, and revenue for our jack-up fleet decreased $189.2 million, or 41%, during 2010 compared to the previous year. During 2010, we cold stacked three additional rigs in the GOM, consisting of two mid-water floaters that returned from Mexico during the year and one jack-up rig. However, the Ocean Courage and Ocean Valor, which commenced drilling operations during 2010, contributed $109.3 million to our revenue during 2010. Total contract drilling expense increased $167.3 million, or 14%, in 2010 compared to 2009, and included normal operating costs for the Ocean Courage and Ocean Valor, as well as increased 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, 2010 and 2009 were as follows:
•
Bad Debt Expense. During 2010, we recovered $9.7 million in previously established reserves for bad debts related to our operations in Egypt and the U.K. During 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $0.9 million related to a previously established reserve for bad debt recorded in 2008 related to our operations in the U.K.
•
Depreciation Expense. Depreciation expense increased $46.7 million, or 13%, during 2010 compared to 2009, primarily due to depreciation associated with capital additions in 2009 and 2010, and included depreciation expense for the Ocean Courage and Ocean Valor, which were placed in service in September 2009 and March 2010, respectively.
•
Gain on Disposition of Assets. Net gain on disposition of assets in 2010 was primarily related to the sale of the Ocean Shield. Net gain on disposition of assets in 2009 included a $6.7 million gain on the sale of the Ocean Tower, which was damaged during a hurricane in 2008.
Interest Expense. Interest expense increased $41.1 million in 2010 compared to 2009, primarily due to a full year of interest expense in 2010 for our 5.875% Senior Notes due 2019, or 5.875% Senior Notes, and our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, issued in May 2009 and October 2009, respectively ($31.9 million). In addition, during 2010, we recorded $4.8 million in interest expense related to uncertain tax positions compared to a $3.4 million net reduction, during 2009, of accrued interest expense related to an uncertain tax position for which the statute of limitations had expired.
Foreign Currency Transaction Gain (Loss). During 2009, we recognized net foreign currency exchange gains of $11.5 million, which included $8.9 million in realized and unrealized gains on foreign currency forward exchange, or FOREX, contracts ($37.3 million in net unrealized gains from mark-to-market accounting and $28.4 million in net realized losses on settled FOREX contracts not designated as accounting hedges). During 2010, we designated all of our FOREX contracts as accounting hedges and, as such, gains and losses on the settlement of these hedged contracts were recorded as a component of operating expenses under “Contract drilling, excluding depreciation.”
Income Tax Expense. 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. We recognized $380.6 million of tax expense on pre-tax income of $1.3 billion for the year ended December 31, 2010 compared to tax expense of $492.2 million on pre-tax income of $1.9 billion in 2009. The effective annual tax rate of 28.5% in 2010 compared unfavorably to the effective annual tax rate of 26.3% in 2009 primarily due to higher taxes for income tax contingencies, as well as taxes associated with the sale of the Ocean Shield.
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.
On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in Mexico expired. As a consequence, we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense, $0.8 million of which had been accrued for penalties.
Contract Drilling Revenue and Expense by Equipment Type
2011 Compared to 2010
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $123.1 million during 2011 compared to 2010. Our newest rigs, the Ocean Courage and Ocean Valor, were under contract in Brazil for all of 2011 and worked a combined 353 incremental revenue earning days, compared to 2010, generating $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 the prior year ($7.8 million). Contract drilling expense increased $8.0 million in 2011, compared to the prior year, primarily due to the Ocean America operating offshore Australia for all of 2011, compared to the prior year 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 reflecting the impact of the cold stacking of rigs 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 in 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.
2010 Compared to 2009
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $27.6 million during 2010 compared to 2009. Our newest ultra-deepwater rigs, the Ocean Courage and Ocean Valor, generated $109.3 million in revenue during 2010 and worked a combined 280 revenue earning days. However, aggregate revenue earned by our other six ultra-deepwater rigs decreased $137.0 million in 2010 compared to 2009, due to 437 fewer revenue earning days ($160.4 million), largely resulting from effects of the April 20, 2010 Macondo well blowout in the GOM, as well as a decrease in average daily revenue earned ($19.3 million). The decline in 2010 revenue was partially offset by the recognition of $12.0 million in incremental mobilization revenue, compared to the prior year, and the receipt of a $30.7 million contract termination fee from a previous customer of the Ocean Endeavor in July 2010. The decrease in revenue earning days in 2010 was primarily attributable to increased downtime associated with incremental mobilization, contract preparation and customer acceptance days for three of our ultra-deepwater rigs that were relocated from the GOM to international locations in 2010 and unplanned downtime due to a force majeure assertion by one of our customers in the GOM following the Macondo incident. Contract drilling expense for our ultra-deepwater floaters increased $111.0 million in 2010 compared to 2009, and included $85.1 million in incremental contract drilling expense incurred by the Ocean Courage and Ocean Valor, as well as $11.7 million in incremental mobilization expenses. Contract drilling expense in 2010 also reflected higher maintenance, inspection, freight, non-income based taxes and other revenue-based fees, partially offset by lower personnel and related costs, including a lower U.S. labor component as more of our rigs worked internationally in 2010 compared to the prior year.
Deepwater Floaters. Revenue generated by our deepwater floaters increased $38.4 million in 2010 compared to 2009, primarily due to 44 additional revenue earning days ($17.4 million). The increase in revenue earning days in 2010, compared to the prior year, resulted from 165 fewer warm stacked days between contracts, partially offset by 80 additional non-revenue earning days due to scheduled shipyard time for inspections, repairs and contract preparation activities and 45 incremental rig mobilization days. In addition, during 2010, we recognized $21.0 million in incremental mobilization revenue compared to the prior year. Contract drilling expense increased $46.8 million in 2010, compared to the prior year, primarily due to $19.7 million in incremental mobilization expense, including amortized mobilization costs, increased personnel-related costs ($12.4 million), higher revenue-based fees ($4.0 million) and shorebase support costs ($9.8 million), which included costs related to our recently established Angola operations and higher costs related to our expanded operations offshore Brazil.
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $128.6 million in 2010 compared to 2009, primarily due to 397 fewer revenue earning days ($114.4 million) combined with a decrease in average daily revenue earned ($39.9 million) in 2010. The decrease in revenue earning days was primarily attributable to increased downtime during 2010 for repairs (95 days) and the cold stacking of rigs (492 days), partially offset by fewer mobilization days (142 fewer days) and warm stacked days (40 fewer days). The impact of these negative factors was partially offset by the recognition of $25.7 million in incremental mobilization fees during 2010 compared to 2009. Contract drilling expense increased $59.1 million during 2010 compared to 2009, primarily due to higher personnel-related expenses ($35.7 million), rig mobilization costs ($8.4 million), including amortized mobilization expenses, revenue-based fees and taxes ($11.1 million) and shorebase support (Brazil and the Falkland Islands) and overhead costs ($7.7 million).
Jack-ups. Revenue earned by our jack-up rigs decreased $189.2 million in 2010 compared to 2009, primarily due to a decrease in average daily revenue earned ($120.0 million) combined with the effect of 354 fewer revenue earning days ($45.1 million) due to the sale of the Ocean Shield and the impact of our cold stacked rigs, including an additional jack-up rig cold stacked in September 2010, partially offset by a decrease in downtime between contracts for our actively marketed jack-ups. The decrease in average daily revenue earned during 2010 resulted primarily from all of our jack-up rigs working at lower dayrates than those earned during 2009 due to weakened market conditions at the time. Comparing periods, the decrease in revenue in 2010 was also attributable to a reduction of $15.4 million in deferred mobilization revenue recognized in 2010 and an $8.8 million demobilization fee earned in 2009 by the Ocean Scepter upon completion of its contract offshore Argentina. Contract drilling expense decreased $45.8 million in 2010 compared to 2009, primarily due to reduced expense for our cold stacked rigs ($26.3 million) and the Ocean Shield ($13.1 million), which we sold in July 2010. Contract drilling expense for our actively marketed jack-up rigs decreased $6.4 million during 2010 compared to 2009.
Sources of Liquidity and Capital Resources
Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. At December 31, 2011, we had $333.8 million in “Cash and cash equivalents” and $902.4 million in “Marketable securities,” representing our investment of cash available for current operations.
We terminated our $285 million credit facility on October 12, 2011, prior to its contractual maturity on November 2, 2011.
Liquidity and Capital Requirements
Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements, our ongoing rig equipment replacement and enhancement programs, and our obligations relating to the construction of our three new drillships. 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 “ - 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.
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.
Contractual Cash Obligations.
The following table sets forth our contractual cash obligations at December 31, 2011.
(1) See Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.
(2) During 2011, we entered into an agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of a deepwater semisubmersible rig, the Ocean Onyx. In December 2010 and during the first half of 2011, we entered into three separate turnkey construction contracts with Hyundai for the construction of three ultra-deepwater drillships. See “- Capital Expenditures” and Note 11 “Commitments and Contingencies - Purchase Obligations” to our Consolidated Financial Statements in Item 8 of this report.
The above table excludes FOREX contracts in the aggregate notional amount of $154.3 million outstanding at December 31, 2011. See further information regarding these contracts in
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, 2011 and 2010, 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, 2011 and 2010, 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, 2011 and 2010, 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 $122.0 million and $117.0 million as of December 31, 2011 and 2010, respectively. A 100-basis point decrease would result in an increase in market value of $142.4 million and $135.5 million as of December 31, 2011 and 2010, 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, 2011, we had FOREX contracts outstanding in the aggregate notional amount of $154.3 million, consisting of $21.9 million in Australian dollars, $81.6 million in Brazilian reais, $25.2 million in British pounds sterling, $14.1 million in Mexican pesos and $11.5 million in Norwegian kroner. These contracts generally settle monthly through June 2012. At December 31, 2011, we have presented the fair value of our outstanding FOREX contracts 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. 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, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 22, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 22, 2012
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, 2011, 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, 2011, 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, 2011 of the Company and our report dated February 22, 2012 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Houston, Texas
February 22, 2012
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
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)
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)
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)
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)
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 49 offshore rigs, consisting of 32 semisubmersibles, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. 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 16, 2012, 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 do 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, 2011, 2010 and 2009.
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.
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, 2011 and 2010, we capitalized $269.5 million and $379.8 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $50 million per project.
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. In 2011, we began capitalizing interest on qualifying expenditures related to the construction of three drillships with expected deliveries in 2013 and 2014. There were no qualifying expenditures during 2010 or 2009.
A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:
Asset Retirement Obligations
At December 31, 2011 and 2010, we had no asset retirement obligations.
Impairment of Long-Lived Assets
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as cold stacking a rig or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
•
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.
A summary of our cold stacked rigs evaluated for impairment at December 31, 2011, 2010 and 2009 was as follows:
We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these eight, seven and four rigs were not subject to impairment at December 31, 2011, 2010 and 2009, respectively.
Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.
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 2011, 2010 or 2009.
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, 2011, 2010 and 2009 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, 2011, 2010 and 2009, we recognized aggregate net foreign currency gains (losses) of $(8.6) million, $1.4 million and $11.5 million, respectively. See Note 6.
Revenue Recognition
Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned 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 initial term of the related drilling contracts (which generally range from 2 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 as incurred.
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 asset.
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.
Recently Issued Accounting Pronouncements
In June 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” or ASU 2011-05, which eliminates the option to present components of other comprehensive income, or OCI, as part of the statement of changes in stockholders’ equity, requires the presentation of each component of net income and each component of OCI either in a single continuous statement or in two separate but consecutive statements and also requires presentation of reclassification adjustments on the face of the financial statement. The FASB subsequently deferred the effective date of certain provisions of this standard pertaining to the reclassification of items out of accumulated other comprehensive income, pending the issuance of further guidance on the matter. The remaining portions of ASU 2011-05 are effective for interim and annual periods beginning after December 15, 2011; however, early adoption is permitted. The adoption of ASU 2011-05 will not have an effect on our financial position, results of operations or cash flows.
In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” or ASU 2011-04. ASU 2011-04 clarifies existing fair value measurement and disclosure requirements, amends certain fair value measurement principles and requires additional disclosures about fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We will incorporate any additional disclosures in our interim and annual financial statements for the calendar year beginning January 1, 2012.
2. Supplemental Financial Information
Consolidated Balance Sheet Information
Accounts receivable, net of allowance for bad debts, consists of the following:
During 2011, we recorded a $5.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables from one of our current customers in Egypt and recovered $12.3 million in bad debts, including $0.2 million from our Egypt customer which had been reserved for in the current year. Recoveries during 2011 also included $8.4 million in final payments from a previous customer in the North Sea and $3.7 million from another customer in Egypt for whom we no longer perform work, both of which were reserved for in previous years. In addition, during 2011, we offset $18.4 million in previously reserved trade receivables against the allowance for bad debts as we had exhausted all methods of recovery against the North Sea customer.
During 2010, we recovered $9.7 million in previously reserved bad debts. Recoveries during 2010 included $4.2 million from a previous customer in the North Sea and $5.5 million from a previous customer in Egypt. No provision for bad debts was deemed necessary for 2010. In 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $0.9 million associated with the reserve for bad debts recorded in 2008.
Prepaid expenses and other current assets consist of the following:
Accrued liabilities consist of the following:
At December 31, 2011 and 2010, we had accrued the first installments or construction milestones payable under our rig construction agreements of $14.6 million and $154.4 million, respectively. See Notes 8 and 11.
Consolidated Statement of Cash Flows Information
We paid interest on long-term debt totaling $82.9 million, $83.5 million and $39.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. We paid $0.9 million in interest on Internal Revenue Service assessments during the year ended December 31, 2010.
We paid $150.5 million, $128.5 million and $176.2 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2011, 2010 and 2009, respectively. We paid $94.8 million, $427.5 million and $252.4 million in U.S. federal income taxes during the years ended December 31, 2011, 2010 and 2009, respectively. We paid state income taxes, net of refunds, of $0.2 million, $0.1 million and $0.2 million during the years ended December 31, 2011, 2010 and 2009, respectively.
Cash payments for capital expenditures for the years ended December 31, 2011, 2010 and 2009 included $28.9 million, $64.9 million and $59.4 million, respectively, of capital expenditures that were accrued but unpaid on December 31, 2010, 2009 and 2008, respectively. Capital expenditures that were accrued but not paid as of December 31, 2011 and 2010 totaled $37.3 million and $28.9 million, respectively. We have included these amounts in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2011 and 2010.
We recorded an income tax benefit of $1.0 million related to the exercise of employee stock options in 2009.
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 for the years ended December 31, 2011, 2010 and 2009 was $5.0 million, $6.0 million and $6.5 million, respectively. Tax benefits recognized for the years ended December 31, 2011, 2010 and 2009 related thereto were $1.7 million, $2.0 million and $2.1 million, respectively.
The fair value of options and SARs granted under the Stock Plan during each of the years ended December 31, 2011, 2010 and 2009 was estimated using the Black Scholes pricing model.
The following are the weighted average assumptions used in estimating the fair value of our options and SARs:
Expected life of stock options and 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 options and SARs.
A summary of activity under the Stock Plan as of December 31, 2011 and changes during the year then ended is as follows:
The weighted-average grant date fair values of awards granted during the years ended December 31, 2011, 2010 and 2009 were $18.17, $23.62 and $28.46, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2011, 2010 and 2009 was $28,000, $8,000 and $1.5 million, respectively. The total fair value of awards vested during the years ended December 31, 2011, 2010 and 2009 was $5.4 million, $6.6 million and $6.6 million, respectively. As of December 31, 2011 there was $5.8 million of total unrecognized compensation cost related to nonvested stock options and SARs granted under the Stock Plan which we expect to recognize over a weighted average period of 2.3 years.
4. Earnings Per Share
A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
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:
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.
Our investments in marketable securities are classified as available for sale and are summarized as follows:
Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:
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 reduce our foreign exchange risk. Our FOREX contracts may obligate us to exchange predetermined amounts of foreign currencies on specified 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 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, 2011 and 2010, we settled FOREX contracts with aggregate notional values of approximately $318.9 million and $332.5 million, respectively, of which the entire aggregate amounts were designated as an accounting hedge. During the year ended December 31, 2009, we settled FOREX contracts with an aggregate notional value of approximately $333.4 million, of which an aggregate notional value of $112.8 million was designated as an accounting hedge.
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, 2011, 2010 and 2009.
The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts not designated as hedging instruments for the years ended December 31, 2011, 2010 and 2009.
The amounts presented in the table above for the year ended December 31, 2009 include net unrealized gains aggregating $37.3 million to record the carrying value of our derivative financial instruments to their fair value. There were no gains or losses associated with FOREX contracts not designated as accounting hedges during the years ended December 31, 2011 and 2010.
As of December 31, 2011, we had FOREX contracts outstanding in the aggregate notional amount of $154.3 million, consisting of $21.9 million in Australian dollars, $81.6 million in Brazilian reais, $25.2 million in British pounds sterling, $14.1 million in Mexican pesos and $11.5 million in Norwegian kroner. These contracts generally settle monthly through June 2012. As of December 31, 2011, 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, 2011 and 2010.
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, 2011, 2010 and 2009.
As of December 31, 2011, the estimated amount of net unrealized losses associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $7.1 million. The net unrealized losses associated with these derivative financial instruments will be reclassified to contract drilling expense.
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 $110.4 million and $69.4 million, or 20% and 12%, respectively, of our total consolidated gross trade accounts receivable balances as of December 31, 2011, and $180.8 million and $52.4 million, or 29% and 8%, respectively, as of December 31, 2010.
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 $6.9 million and $31.9 million at December 31, 2011 and 2010, respectively. See Note 2.
During 2009, we amended an existing contractual agreement at a customer’s request to provide short-term financial relief. The amended contract obligates the customer to pay us, over the term of the six-well drilling program, an aggregate drilling rate of $560,000 per day, consisting of $75,000 per day payable in accordance with our normal credit terms (due 30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day, payable through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties.
At December 31, 2011, the six-well drilling program had been completed and $95.8 million was payable to us from the NPI. We expect to receive the balance within the next twelve months and have presented this amount in “Accounts receivable, net of allowance for bad debts” in our Consolidated Balance Sheets. At December 31, 2011, we believe that collectability of the amount owed pursuant to the NPI arrangement was reasonably assured.
At December 31, 2010, $85.0 million was payable to us from the NPI, of which $49.6 million and $35.4 million were presented as “Accounts receivable, net of allowance for bad debts” and “Long-term receivable,” respectively, in our Consolidated Balance Sheets.
Fair Values
The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts, long-term receivables, and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are shown below.
We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2011 and 2010, respectively. 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. The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it was practicable to estimate that value:
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Cash and cash equivalents - The carrying amounts approximate fair value because of the short maturity of these instruments.
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Marketable securities - The fair values of the debt securities, including residential mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2011 and 2010, respectively.
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Accounts receivable and accounts payable - The carrying amounts approximate fair value based on the nature of the instruments.
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Forward exchange contracts - The fair value of our FOREX contracts was based on both quoted market prices and valuations derived from pricing models on December 31, 2011 and 2010, respectively.
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Long-term receivable - The carrying amount approximates fair value based on the nature of the instrument.
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Long-term debt - The fair value of our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, 5.875% Senior Notes due 2019, or 5.875% Senior Notes, 4.875% Senior Notes due July 1, 2015, or 4.875% Senior Notes, and 5.15% Senior Notes due September 1, 2014, or 5.15% Senior Notes, was based on the quoted closing market price on December 31, 2011 and 2010, respectively, from brokers of these instruments.
Certain of our assets and liabilities are required to be measured at fair value in accordance with GAAP. 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, 2011 consisted of cash held in money market funds of $303.9 million and investments in U.S. Treasury securities of $902.0 million. Our Level 1 assets at December 31, 2010 consisted of cash held in money market funds of $442.2 million and investments in U.S. Treasury Bills of $600.0 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 are 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.
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.
Assets and liabilities measured at fair value on a recurring basis are summarized below:
8. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
Construction work-in-progress at December 31, 2011 included $14.6 million and $490.2 million related to the construction of the Ocean Onyx and our three drillships, respectively. At December 31, 2010, we had recorded the first $154.4 million payable under our initial drillship construction agreement as “Other Assets” in our Consolidated Balance Sheets. During 2011, we entered into two additional drillship construction agreements and also recorded the first installments paid under these agreements as “Other Assets” in our Consolidated Balance Sheets. We transferred aggregate payments of $478.3 million related to our drillships into construction work-in-progress in August 2011 and commenced capitalization of interest. See Note 11.
9. Long-Term Debt
Our long-term debt is comprised as follows:
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, 2011 and 2010, the carrying value of our long-term debt was as follows:
As of December 31, 2011, the aggregate annual maturity of our long-term debt was as follows:
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:
The components of our accumulated other comprehensive income (loss) included in our Consolidated Balance Sheets are as follows:
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 30 lawsuits filed in Louisiana and Mississippi 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 have filed a declaratory judgment action in Texas state court against NuStar Energy LP, the successor to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. 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 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 position, 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 per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. 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, 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. At December 31, 2010, our estimated liability for personal injury claims was $35.0 million, of which $11.1 million and $23.9 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:
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the severity of personal injuries claimed;
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significant changes in the volume of personal injury claims;
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the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
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inconsistent court decisions; and
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the risks and lack of predictability inherent in personal injury litigation.
Purchase Obligations. In December 2011, we entered into an agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of a moored semisubmersible rig designed to operate in water depths up to 6,000 feet. The rig, to be named the Ocean Onyx, will be constructed utilizing the hull of one of our mid-water floaters that previously operated as the Ocean Voyager. The project is estimated to be completed in the third quarter of 2013 at an aggregate cost of approximately $300 million, including commissioning, spares and project management costs. The contracted price due to Keppel for the construction of the rig 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.
In addition, since December 2010, we have entered into three separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of three dynamically positioned, ultra-deepwater drillships, with deliveries scheduled for the second and fourth quarters of 2013 and in the second quarter of 2014. The aggregate cost of the three drillships, including commissioning, spares and project management, is expected to be approximately $1.8 billion.
The contracted price of each drillship is payable in two installments. At December 31, 2010, we had accrued the initial installment payable to Hyundai for the first drillship of $154.4 million in “Accrued liabilities” in our Consolidated Balance Sheets. The first installments for all three drillships, aggregating $478.3 million, were paid in the first and second quarters of 2011.
At December 31, 2011 and 2010, 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 2015. Total rent expense amounted to $9.3 million, $8.0 million and $6.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Future minimum rental payments under leases are approximately $1.8 million, $1.1 million, $0.7 million and $0.1 million for the years ending December 31, 2012, 2013, 2014 and 2015, respectively. There are no minimum future rental payments under leases after 2015.
Letters of Credit and Other. We were contingently liable as of December 31, 2011 in the amount of $108.4 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit that included one $11.8 million bond, which had been purchased from a related party after obtaining competitive quotes. Agreements relating to approximately $88.2 million of performance bonds can require collateral at any time. As of December 31, 2011, 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 $1.1 million, $1.3 million and $1.1 million by Loews for these support functions during the years ended December 31, 2011, 2010 and 2009, respectively.
In addition, since 2006 we have purchased performance and appeal bonds in support of our drilling operations offshore Mexico and workers compensation claims, respectively, from affiliates of a majority-owned subsidiary of Loews after obtaining competitive quotes. At December 31, 2011, one such performance bond totaling $11.8 million was outstanding. Premiums and fees associated with bonds purchased from affiliates totaled $80,000, $58,000 and $213,000 in 2011, 2010 and 2009, 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 Chairman of the Board of Directors, President and Chief Executive Officer of SEACOR Holdings Inc. is also a member of our Board of Directors. For the years ended December 31, 2011, 2010 and 2009, we paid $0.1 million, $3.1 million and $3.6 million, respectively, for the hire of such vessels and such services.
During the years ended December 31, 2011, 2010 and 2009 we made payments of $1.2 million, $1.0 million and $2.1 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 $1.7 billion of undistributed foreign earnings and profits. Although we do not intend to repatriate the earnings of DOIL, and have not provided U.S. income taxes for such earnings, except to the extent that such earnings were immediately subject to U.S. income taxes, these earnings could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practical to estimate this potential liability.
In 2010 we had 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 on December 17, 2010, in conjunction with our decisions to build three new drillships overseas, caused us to reassess our intent to repatriate the earnings of DEAL to the U.S. We now plan to 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 the year ended December 31, 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:
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:
Significant components of our deferred income tax assets and liabilities are as follows:
(1) $6.8 million and $9.6 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2011 and 2010, 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:
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:
At December 31, 2011, all $41.2 million of the net unrecognized tax benefits would affect the effective tax rate if recognized.
We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. During the years ended December 31, 2011 and 2010, we recognized $0.2 million and $4.8 million of interest expense related to uncertain tax positions, respectively. During the year ended December 31, 2009, we recorded a net reduction to interest expense of $3.4 million. During the year ended December 31 2011, we recorded a net reduction to penalty related tax expense for uncertain tax positions of $3.0 million. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2010 and 2009 was $12.0 million and $4.7 million, respectively. Accruals for the payment of interest and penalties in our Consolidated Balance Sheets at December 31, 2011 and 2010 were $31.4 million and $34.2 million, respectively.
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.
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 2010. We are currently under audit in several of these jurisdictions. We do not anticipate that any adjustments resulting from the tax audits will have a material impact on our consolidated results of operations, financial position and cash flows. During 2011, an audit by the U.S. Internal Revenue Service for the year 2008 was completed without any adjustment proposed by the auditors.
The Brazilian tax authorities have audited our income tax returns for the years 2000, 2004 and 2005 and are currently auditing our income tax return for the year 2007. 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. 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 $13.8 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 $3.5 million is penalty related. 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 position and cash flows. 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.
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. We have appealed the tax assessments and are awaiting the outcome of the appeals. In January 2012, we received tax assessments for the tax year 2006 of approximately $24.4 million including interest and penalties. We do not anticipate that any adjustments resulting from the tax audits of any of these years will have a material impact on our consolidated results of operations, financial position and cash flows.
As of December 31, 2011, we had recorded a deferred tax asset of $27.2 million for the benefit of NOL carryforwards related to our international operations. Approximately $8.2 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $19.0 million relates to NOL carryforwards of our Mexican entities. Unless utilized, the tax benefits of these Mexican NOL carryforwards will expire between 2014 and 2021 as follows:
As of December 31, 2011, a valuation allowance of $26.4 million has been recorded for our NOLs as only $0.8 million of the deferred tax asset is more likely than not to be realized.
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 the years ended December 31, 2011, 2010 and 2009, we made a profit-share contribution of 4%, 4% and 5%, respectively, of participants’ defined compensation and in each year 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, 2011, 2010 and 2009, our provision for contributions was $21.5 million, $23.8 million and $26.0 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 of 5.25% of the employee’s defined compensation per year for employees working in the U.K. sector of the North Sea and up to a maximum of 9% of the employee’s defined compensation per year for U.K. nationals working in the Norwegian sector of the North Sea. Our provision for contributions was $1.2 million, $1.2 million and $1.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During the years ended December 31, 2011, 2010 and 2009, we contributed 4%, 4% and 5%, respectively, of participants’ defined compensation and in each year matched up to 6% of each employee’s compensation contributed to the International Savings Plan. Our provision for contributions was $2.9 million, $2.8 million and $2.5 million for the years ended December 31, 2011, 2010 and 2009, 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, 2011, 2010 and 2009 was approximately $245,000, $238,000 and $241,000, 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 among all divisions and locations, including the nature of services provided and the type of customers of such services.
Revenues from contract drilling services by equipment-type are listed below:
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, 2011, our drilling rigs were located offshore 13 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.
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, 2011, 2010 and 2009, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.
A substantial portion of our assets is 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 are expected to operate.
The following table presents our long-lived tangible assets by geographic location as of December 31, 2011, 2010 and 2009.
(1) Long-lived tangible assets in the Australia/Asia/Middle East region as of December 31, 2011 include $490.2 million in construction work-in-progress for three drillships under construction in South Korea.
The following table presents the countries in which material concentrations of our long-lived tangible assets were located as of December 31, 2011, 2010 and 2009:
(1) Assets in South Korea, as of December 31, 2011, include $490.2 million in construction work-in-progress for our three drillships under construction.
As of December 31, 2011, 2010 and 2009, 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, 2011, 2010 and 2009 that contributed more than 10% of our total revenues are as follows:
16. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 2011 and 2010 is shown below.
(a) Results for the fourth quarter of 2011 include a $1.3 million recovery of bad debt reserves recorded in previous years.
(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.
(c) Results for the fourth quarter of 2010 include a $3.9 million recovery of bad debt reserves recorded in previous years.
(d) Results for the fourth quarter of 2010 reflect a reduction in income tax expense, partially attributable to recording the full year tax effect of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 that was passed in mid-December 2010.
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, 2011. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2011.
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, 2011. 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, 2011, 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 2011 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 2012 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
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(2) Exhibit Index
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 23, 2012.
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 23, 2012
/s/ GARY T. KRENEK*
Gary T. Krenek
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
February 23, 2012
/s/ BETH G. GORDON*
Beth G. Gordon
Controller (Principal Accounting Officer)
February 23, 2012
/s/ JAMES S. TISCH*
James S. Tisch
Chairman of the Board
February 23, 2012
/s/ JOHN R. BOLTON*
John R. Bolton
Director
February 23, 2012
/s/ CHARLES L. FABRIKANT*
Charles L. Fabrikant
Director
February 23, 2012
/s/ PAUL G. GAFFNEY II*
Paul G. Gaffney II
Director
February 23, 2012
/s/ EDWARD GREBOW*
Edward Grebow
Director
February 23, 2012
/s/ HERBERT C. HOFMANN*
Herbert C. Hofmann
Director
February 23, 2012
/s/ CLIFFORD M. SOBEL*
Clifford M. Sobel
Director
February 23, 2012
/s/ ANDREW H. TISCH*
Andrew H. Tisch
Director
February 23, 2012
/s/ RAYMOND S. TROUBH*
Raymond S. Troubh
Director
February 23, 2012
*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).
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).
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+
Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (amended and restated as of December 18, 2009) (incorporated by reference to Exhibit 10.9 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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.