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 47 offshore rigs consisting of 32 semisubmersibles, 14 jack-ups and one drillship. 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.
The Fleet
Our fleet includes some of the most technologically advanced rigs in the world, enabling us to offer a broad range of services worldwide in various markets, including the deepwater, harsh environment, conventional semisubmersible and jack-up markets.
Semisubmersibles. We own and operate 32 semisubmersibles, consisting of 13 high-specification and 19 intermediate 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 are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig’s position over a drillsite. We have five semisubmersible rigs in our fleet with this capability.
Our high-specification semisubmersibles are generally capable of working in water depths of 4,000 feet or greater or in harsh environments and have other advanced features, as compared to intermediate semisubmersibles. As of January 25, 2010, seven of our 13 high-specification semisubmersibles, including the recently acquired Ocean Courage, were located in the United States, or U.S., Gulf of Mexico, or GOM. At that date we had two high- specification semisubmersibles rigs operating offshore Brazil, while a third was en route to Brazil from the GOM. Of our remaining high-specification semisubmersibles, one was located offshore each of Malaysia and Angola, while the final rig, the Ocean Valor, was completing its commissioning in Singapore. See “ - Fleet Enhancements and Additions.”
Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet. As of January 25, 2010, we had 19 intermediate semisubmersible rigs in various locations around the world. Seven of these semisubmersibles were operating offshore Brazil and an eighth unit was en route to Brazil; three were located in the North Sea; two each were located offshore Australia and offshore Mexico; one was located in the GOM and one offshore Vietnam. One unit was en route to the Falkland Islands, and our final intermediate semisubmersible rig, the Ocean Bounty, was in the process of being cold stacked in Malaysia.
Drillship. We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 25, 2010. Drillships, which are typically self-propelled, are positioned over a drillsite through the use of either an anchoring system or a dynamic-positioning system similar to those used on certain semisubmersible rigs. Deepwater drillships compete in many of the same markets as do high-specification semisubmersible rigs.
Both semisubmersible rigs and drillships are commonly referred to as floaters in the offshore drilling industry.
Jack-ups. We currently have 14 jack-up drilling rigs. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. 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. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig’s legs. 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 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. This is particularly important when attempting to drill over existing platforms. Cantilever rigs have historically earned higher dayrates and achieved greater utilization compared to slot rigs, which do not have this capability.
As of January 25, 2010, six of our 14 jack-up rigs were located in the GOM and a seventh rig, the Ocean Scepter, was en route from Uruguay for a six-well drilling program in the GOM. Four of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. We cold-stacked the three mat-supported jack-up rigs located in the GOM during the second quarter of 2009 and are no longer actively marketing these drilling units. Of our seven remaining jack-up rigs, all of which are independent-leg cantilevered units, two each were located offshore Egypt and Mexico, and one was located offshore each of Indonesia, Croatia and the Joint Petroleum Development Area, or JPDA, between Australia and Timor Leste.
Fleet Enhancements and Additions. Our long-term strategy has been to economically upgrade our fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles, in order to maximize the utilization of, and dayrates earned by, the rigs in our fleet. During 2009, we acquired two new-build deepwater, semisubmersible, dynamically-positioned drilling rigs, the Ocean Courage (June 2009) and the Ocean Valor (September 2009). As of January 25, 2010, the Ocean Courage was in process of completing its commissioning and preparing for its first contract in the GOM, which we expect to begin in the first quarter of 2010. We expect commissioning of the Ocean Valor to be completed in Singapore in the first quarter of 2010.
In addition, excluding our two new deepwater floaters acquired in 2009, we have, since 1995, increased the number of our rigs capable of operating in 3,500 feet or more of water from three rigs to 14 (11 of which are high-specification units), primarily by upgrading our existing fleet. Seven of these upgrades were to our Victory-class semisubmersible rigs, the design of which is well-suited for significant upgrade projects. We have two additional Victory-class intermediate semisubmersibles that could potentially be upgraded at some time in the future.
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 - Sources of Liquidity and Capital Resources - Liquidity and Capital Requirements” in Item 7 of this report.
More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 25, 2010, is set forth in the table below.
Attributes
DP = Dynamically-Positioned/Self-Propelled
MS = Mat-Supported Slot Rig
3M = Three Mud Pumps
IC = Independent-Leg Cantilevered Rig
VC = Victory-Class
4M = Four Mud Pumps
MC = Mat-Supported Cantilevered Rig
SP = Self-Propelled
15K = 15,000 psi well control system
See the footnotes to this table on the following page.
(a)
Nominal water depth (in feet), as described above for semisubmersibles and drillships, reflects the current operating water depth capability for each drilling unit. In many cases, individual rigs are capable of drilling, or have drilled in, greater water depths. In all cases, floating rigs are capable of working successfully at greater depths than their nominal water depth. On a case by case basis, we may achieve a greater depth capacity by providing additional equipment.
(b)
Such enhancements may include water depth upgrades, mud pump additions and increases in deck load capacity
(c)
GOM means U.S. Gulf of Mexico. Four of our drilling rigs were en route between geographic locations. They have been presented in the preceding table in the geographic location in which they are expected to commence drilling operations in 2010.
(d)
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:
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the Gulf of Mexico, including the U.S. and Mexico;
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South America, principally in Brazil;
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Europe, principally in the United Kingdom, or U.K., and Norway;
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the Mediterranean Basin, including Egypt;
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Africa, currently in Angola;
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Australia and Asia, including Malaysia, Indonesia and Vietnam; and
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the Middle East, including Kuwait, Qatar and Saudi Arabia.
We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 17 “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 competitive bidding, although it is not unusual for us to be awarded drilling contracts without competitive bidding. Our drilling contracts generally provide for a basic drilling rate on a fixed dayrate basis regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for lower 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 conditions beyond our control. 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.
A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or a group of wells, which we refer to as a well-to-well contract, or a fixed term, which we refer to as a term contract, and 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 other events beyond the control of either party to the contract. In addition, certain of our contracts permit the customer to terminate the contract early by giving notice, and in most circumstances may require 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 - The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market,” “Risk Factors - Our drilling contracts may be terminated due to events beyond our control,” “Risk Factors - Our business involves numerous operating hazards, and we are not fully insured against all of them” and “Risk Factors - We
have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico” in
Item 1A of this report, which are incorporated herein by reference.
Employees
As of December 31, 2009, we had approximately 5,500 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.
Access to Company Filings
We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The information contained on our website, or on other websites linked to our website, is not part of this report.
Item 1A.
Risk Factors.
Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that 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:
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worldwide demand for oil and gas;
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the level of economic activity in energy-consuming markets;
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the worldwide economic environment or economic trends, such as recessions;
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the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;
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the level of production in non-OPEC countries;
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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;
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the cost of exploring for, producing and delivering oil and gas;
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the discovery rate of new oil and gas reserves;
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the rate of decline of existing and new oil and gas reserves;
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available pipeline and other oil and gas transportation capacity;
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the ability of oil and gas companies to raise capital;
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weather conditions in the United States and elsewhere;
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the policies of various governments regarding exploration and development of their oil and gas reserves;
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development and exploitation of alternative fuels;
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competition for customers’ drilling budgets from land-based energy markets around the world;
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domestic and foreign tax policy; and
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advances in exploration and development technology.
The continuing global financial crisis and worldwide economic downturn has had, and may continue to have, a negative impact on our business and financial condition.
The continuing worldwide financial crisis has reduced the availability of liquidity and in some cases has reduced the availability of and/or increased the cost of credit to fund the continuation and expansion of industrial business operations worldwide, and has led to a worldwide economic recession. This deterioration of the worldwide economy has resulted in reduced demand for crude oil and natural gas, exploration and production activity and offshore drilling services that has had a negative impact on our business and financial condition, including declines in dayrates earned by our drilling rigs and a decrease in new contract activity, which may continue and may worsen.
In addition, the worldwide economic recession has had, and could continue to have, a negative impact on our customers and/or our suppliers including, among other things, causing them to fail to meet their obligations to us. Additionally, if a potential customer is unable to obtain an adequate level of credit, it may preclude us from doing business with that potential customer. Similarly, the restricted credit market could affect lenders participating in our credit facility, making them unable to fulfill their commitments and obligations to us. Any such reductions in drilling activity or failure by our customers, suppliers or lenders to meet their contractual obligations to us, or our inability to secure additional financing, could adversely affect 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 recent years and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered. Mergers among oil and natural gas exploration and production companies, as well as the contraction of the global economy, have reduced the number of available customers, increasing competition.
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 our drilling services, we have cold stacked three of our rigs as of the date of this report and are in the process of cold stacking a fourth unit. 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 50 jack-up rigs and 70
floaters on order and scheduled for delivery between 2010 and 2012. The resulting increases in rig supply could be sufficient to further 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. This potential oversupply of uncontracted rigs is greater in the jack-up market than it is in the floater market. However, 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.
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 $8.5 billion for contracted future work extending, in some cases, until 2016. Generally, contract backlog only includes future earnings under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been 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. However, the number of potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. In 2009, our five largest customers in the aggregate accounted for 41% of our consolidated revenues. We expect Petrobras, who accounted for approximately 15% of our consolidated revenues in 2009, to continue to be a significant customer in 2010. 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.
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 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 suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our financial position, results of operations or cash flows.
Our business involves numerous operating hazards, and we are not fully insured against all of them.
Our operations are subject to the usual hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and natural disasters such as hurricanes. The occurrence of these 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 environmental damage, and could have a material adverse effect on our results of operations and financial condition. 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. In addition, offshore drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather, and we do not typically retain loss-of-hire insurance policies to cover our rigs. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. Pollution and environmental risks generally are not fully insurable. We may also be subject to damage claims by oil and gas companies or other parties.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses, or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including, among other things, liability risk for certain amounts of excess coverage and certain physical damage risk. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all 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.
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 has been limited, and the cost for such coverage has increased substantially, 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 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:
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terrorist acts, war and civil disturbances;
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piracy or assaults on property or personnel;
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kidnapping of personnel;
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expropriation of property or equipment;
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renegotiation or nullification of existing contracts;
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changing political conditions;
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foreign and domestic monetary policies;
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the inability to repatriate income or capital;
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difficulties in collecting accounts receivable and longer collection periods;
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fluctuations in currency exchange rates;
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regulatory or financial requirements to comply with foreign bureaucratic actions;
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travel limitations or operational problems caused by public health threats; and
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changing taxation policies.
We are subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations. In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
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the equipping and operation of drilling units;
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import-export quotas or other trade barriers;
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repatriation of foreign earnings;
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oil and gas exploration and development;
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taxation of offshore earnings and earnings of expatriate personnel; and
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use and compensation of local employees and suppliers by foreign contractors.
Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments may adversely affect our ability to compete.
As of the date of this report, the greatest concentration of our operating assets outside the United States was offshore Brazil, where we had 12 rigs in our fleet either currently working or contracted to work during 2010.
Our drilling contracts offshore Mexico expose us to greater risks than we normally assume.
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 risks than we normally assume, such as exposure to greater environmental liability. In addition, each contract can be terminated by PEMEX on 30 days 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 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 and operating structures 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 our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; 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, our wholly-owned Cayman Islands subsidiary. Since forming this subsidiary it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign operations. During 2007, DOIL made a non-recurring distribution to its U.S. parent company, and we recognized U.S. federal income tax expense on the portion of the distribution that consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the future earnings of DOIL to finance foreign activities, except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of DEAL, and U.S. income taxes will be provided on such earnings. 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 or as they relate to DEAL. 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 an adverse effect on our financial position, results of operations and cash flows.
Future acts of terrorism and other political and military events could adversely affect the markets for our drilling services.
Terrorist acts and political events around the world have resulted in military actions in Afghanistan and Iraq, as well as related political and economic unrest in various parts of the world. Future terrorist attacks and the continued threat of terrorism in the U.S. or 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 adversely affect the market for our offshore drilling services, our dayrates or utilization and, accordingly, our financial position, results of operations and cash flows. In addition, it has been reported that terrorists might target domestic energy facilities. While we take steps that we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure these assets, completely protect them against a terrorist attack or obtain adequate insurance coverage for terrorist acts at reasonable rates. Moreover, U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Public health threats could have a material adverse effect on our operations and financial results.
Public health threats such as outbreaks of highly communicable diseases, which periodically occur in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may have a material adverse effect on our financial position, results of operations and cash flows.
We may be subject to litigation that could have an 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 an adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.
Governmental laws and regulations 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.
Governments in some foreign 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 industries. 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 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.
The Minerals Management Service of the U.S. Department of the Interior, or MMS, has established guidelines for drilling operations in the GOM. We believe that we are currently in compliance with the existing regulations set forth by the MMS with respect to our operations in the GOM; however, these regulations are continually under review by the MMS and may change from time to time. Implementation of additional MMS regulations may subject us to increased costs of operating, or a reduction in the area and/or periods of operation, in the GOM.
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.
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 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. In addition, the entrance of new participants into the offshore drilling market would 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 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. 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;
•
unanticipated cost increases;
•
weather interferences;
•
difficulties in obtaining necessary permits or in meeting permit conditions;
•
design and engineering problems;
•
customer acceptance delays;
•
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 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.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2009, 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 may limit our liquidity and flexibility in obtaining additional financing and pursuing 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 19, 2010 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 and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, 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 containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located, 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 and two buildings totaling 65,000 square feet and 11 acres of land in Macae, Brazil, for our South American operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Singapore, Egypt, Angola, Vietnam and Mexico to support our offshore drilling operations.
Item 3. Legal Proceedings.
Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
Executive Officers of the Registrant
We have included information on our executive officers in Part I of this report in reliance on General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of Directors to serve until the next annual meeting of our Board of Directors, or until their successors are duly elected and qualified, or until their earlier death, resignation, disqualification or removal from office. Information with respect to our executive officers is set forth below.
Lawrence R. Dickerson has served as our President and a Director since March 1998 and as our Chief Executive Officer since June 2008. Mr. Dickerson served as our Chief Operating Officer from March 1998 to June 2008. Mr. Dickerson served on the United States Commission on Ocean Policy from 2001 to 2004.
John M. Vecchio has served as Executive Vice President since August 2009. Mr. Vecchio previously served as our Senior Vice President- Technical Services from April 2002 to July 2009.
Gary T. Krenek has served as a Senior Vice President and our Chief Financial Officer since October 2006. Mr. Krenek previously served as our Vice President and Chief Financial Officer since March 1998.
William C. Long has served as a Senior Vice President and our General Counsel and Secretary since October 2006. Mr. Long previously served as our Vice President, General Counsel and Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through February 2001.
Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.
Lyndol L. Dew has served as a Senior Vice President since September 2006. Previously, Mr. Dew served as our Vice President - International Operations from January 2006 to August 2006 and as our Vice President - North American Operations from January 2003 to December 2005.
Robert G. Blair has served as a Senior Vice President since July 2009. Mr. Blair previously served as our Vice President - Contracts & Marketing - North & South America from November 1999 to June 2009.
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 19, 2010 there were approximately 218 holders of record of our common stock. This number represents registered shareholders and does not include shareholders who hold their shares institutionally.
Dividend Policy
In 2009, we paid regular cash dividends of $0.125 per share of our common stock on March 2, June 1, September 1 and December 1. We also paid special cash dividends in 2009 of $1.875 per share of our common stock on March 2, June 1, September 1 and December 1. In 2008, we paid regular cash dividends of $0.125 per share of our common stock on March 3, June 2, September 1 and December 1. We also paid special cash dividends in 2008 of $1.25 per share of our common stock on March 3, June 2 and September 1 and $1.875 per share of our common stock on December 1.
On February 3, 2010, we declared a regular cash dividend and a special cash dividend of $0.125 and $1.875, respectively, per share of our common stock. Both the regular and special cash dividends are payable on March 1, 2010 to stockholders of record on February 12, 2010.
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 and a Peer Group Index over the five year period ended December 31, 2009.
Comparison of 2005 - 2009 Cumulative Total Return (1)
(1)
Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2004 in our common stock, the S&P 500 Index and a peer group index comprised of a group of other companies in the contract drilling industry.
Our dividend history for the periods reported above is as follows:
(2)
The peer group is comprised of the following companies: ENSCO International Incorporated, Noble Drilling Corporation, Pride International, Inc., Rowan Companies, Inc. and Transocean Inc. Total return calculations were weighted according to the respective company’s market capitalization.
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 47 offshore drilling rigs consists of 32 semisubmersibles, 14 jack-ups and one drillship.
Overview
Industry Conditions
The global economy remained weak in the fourth quarter of 2009 and into the first quarter of 2010 and energy prices continued to be volatile. Given the unpredictable economic environment, the demand for our services and the dayrates we were able to command for new contracts softened. This volatility and uncertainty could continue until the global economy improves. Absent global economic improvement the decline in drilling activity could be further exacerbated by the influx of new-build rigs over the next several years, particularly in regard to jack-up units.
We have experienced negative effects of the current market such as customer credit problems, customers attempting to renegotiate or terminate contracts, one customer seeking bankruptcy protection, a further slowing in the pace of new contracting activity, declines in dayrates for new contracts, declines in utilization and the stacking of idle equipment. Nevertheless, during 2009, we added new commitments to our contract backlog. We entered 2010 with a contract backlog approaching $8.5 billion, which we expect to help mitigate the impact of the current market on us in 2010.
Floaters
Approximately 81% of the time on our intermediate and high-specification floater rigs is committed for 2010. Additionally, 55% of the time on our floating rigs is committed in 2011.
International Jack-ups
The industry’s jack-up market is divided between an international sector and a U.S. sector, with the international sector historically characterized by contracts of longer duration and higher prices, compared to the generally shorter term and lower priced domestic sector. However, in 2009 demand and dayrates softened internationally as existing rigs rolled off contract and met competition from un-contracted new-build jack-ups that came to market. It is expected that this oversupply of jack-up rigs will have an increasingly negative impact on the international sector during 2010 and beyond.
GOM Jack-ups
In the domestic jack-up sector, lower natural gas prices have negatively impacted both demand and dayrates. In response, to reduce costs, we have cold-stacked three of our lower-end jack-up units, and they are not being actively marketed. Our four remaining higher-specification jack-ups in the GOM are largely working under short-term contracts. Absent a sustained improvement in energy prices, weakness in the GOM jack-up market is likely to continue in 2010, with the possibility of additional rigs being cold-stacked by the industry in an effort to help bring equipment supply and demand into equilibrium.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of February 1, 2010, October 22, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009) and February 5, 2009 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2008). The October 2009 period includes both firm commitments (typically represented by signed contracts), as well as previously-disclosed letters of intent, or LOIs, where indicated. An LOI is subject to customary conditions, including the execution of a definitive agreement, and as such may not result in a binding contract. 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 95-98% 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, 2010 for our high-specification floaters includes $1.3 billion attributable to our expected operations offshore Brazil for the years 2010 to 2016.
(2)
Contract drilling backlog as of February 1, 2010 for our intermediate semisubmersibles includes $2.9 billion attributable to our expected operations offshore Brazil for the years 2010 to 2015.
(3)
Contract drilling backlog as of October 22, 2009 included an aggregate $124.1 million in contract drilling revenue related to future work for one of our high-specification floaters for which a definitive agreement was subsequently reached.
The following table reflects the amount of our contract drilling backlog by year as of February 1, 2010.
(1)
Contract drilling backlog as of February 1, 2010 for our high-specification floaters includes $374.0 million, $294.0 million and $135.0 million for the years 2010, 2011 and 2012, respectively, and $476.0 million in the aggregate for the years 2013 to 2016, attributable to our expected operations offshore Brazil.
(2)
Contract drilling backlog as of February 1, 2010 for our intermediate semisubmersibles includes $715.0 million, $788.0 million and $732.0 million for the years 2010, 2011 and 2012, respectively, and $698.0 million in the aggregate for the years 2013 to 2015, attributable to our expected operations offshore Brazil.
The following table reflects the percentage of rig days committed by year as of February 1, 2010. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning date for the Ocean Valor.
(1)
Includes approximately 970 and 80 scheduled shipyard, survey and mobilization days for 2010 and 2011, respectively.
Casualty Loss
In September 2008, the jack-up rig Ocean Tower sustained significant damage during Hurricane Ike, which impacted the Gulf of Mexico and the upper Texas and Louisiana Gulf coasts. The Ocean Tower lost its derrick, drill floor and drill floor equipment during the hurricane. During the third quarter of 2008, we wrote off the approximately $2.6 million net book value of the derrick, drill floor and drill floor equipment for the Ocean Tower and accrued $3.7 million in estimated salvage costs for the recovery of equipment from the ocean floor. The aggregate amount of these items was reflected in “Casualty Loss” in our Consolidated Statements of Operations for the year ended December 31, 2008 included in Item 8 of this report.
In December 2008, we entered into an agreement to sell the Ocean Tower and transferred the $32.2 million net book value of the rig to “Assets held for sale” in our Consolidated Balance Sheets included in Item 8 of this report. The sale of the Ocean Tower was completed on October 26, 2009, and we recognized a $6.7 million gain on the sale which has been presented as “Gain on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2009 included in Item 8 of this report. The agreement prohibited the competitive use of the rig, which is expected to be deployed by the purchaser as an accommodation unit.
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 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.
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.
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.
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 “ready-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.
For 2010, we expect depreciation expense to increase approximately $26.6 million compared to 2009, due to the 2009 acquisitions of the Ocean Courage and Ocean Valor. See “ - Sources of Liquidity and Capital Resources - Liquidity and Capital Requirements - Capital Expenditures.”
Periods of high, sustained utilization may result in cost increases for maintenance and repairs in order to maintain our equipment in proper, working order. In addition, during periods of high activity and dayrates, higher prices generally pervade the entire offshore drilling industry and its support businesses, which causes our costs for goods and services to increase.
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 surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance costs may be required resulting from the 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 2010, five of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 320 days in the aggregate. We also expect to spend an additional approximately 730 days during 2010 for intermediate surveys, the mobilization of rigs, commissioning and 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 or cash flows. However, under our current insurance policy that expires on May 1, 2010, we continue to 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.
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 years ended December 31, 2008 and 2007, we capitalized interest of $16.9 million and $19.3 million, respectively, on qualifying expenditures related to the upgrades of the Ocean Endeavor and Ocean Monarch for ultra-deepwater service and the construction of two jack-up rigs, the Ocean Shield and Ocean Scepter, through the date of each project’s completion. The upgrades of the Ocean Endeavor and Ocean Monarch were completed in March 2007 and December 2008, respectively. Construction of the Ocean Shield and Ocean Scepter was completed in May 2008 and August 2008, respectively. We did not capitalize interest on any qualifying assets during 2009.
Interest Expense. We expect interest expense in 2010 to increase approximately $32.5 million compared to 2009 as a result of our issuance of $500.0 million in aggregate principal amount of 5.70% Senior Notes due 2039, or 5.70% Senior Notes, in October 2009 and $500.0 million aggregate principal amount of 5.875% Senior Notes due 2019, or 5.875% Senior Notes, in May 2009. See “ - Sources of Liquidity and Capital Resources - Liquidity and Capital Requirements - 5.70% Senior Notes” and “ - Sources of Liquidity and Capital Resources - Liquidity and Capital Requirements - 5.875% Senior Notes.” Also see Note 10 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:
Property, Plant and Equipment. We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which meet certain criteria, are capitalized. Depreciation is amortized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives. Our management makes judgments, assumptions and estimates regarding capitalization, useful lives and salvage values. Changes in these judgments, assumptions and estimates could produce results that differ from those reported.
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 the cold-stacking a rig or excess spending over budget on a new-build 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, ready-stacked or cold-stacked; and
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salvage value for each rig.
Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates. We also 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), or alternatively the impact of a 5% reduction in utilization (again holding all other assumptions and estimates in the model constant) as part of our analysis.
As of December 31, 2009, we had cold-stacked our three mat-supported jack-up rigs and were in the process of cold-stacking an intermediate semisubmersible drilling rig in Malaysia. We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we have concluded that these four rigs were not subject to impairment at December 31, 2009.
At December 31, 2009, the remaining rigs in our fleet were currently working under contract, mobilizing to new locations or being actively marketed. We do not believe that current circumstances indicate that there was an impairment of these 43 rigs at December 31, 2009.
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 deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. 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 estimate our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models.
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.
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 and the geographic regions in which they operate to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.
Years Ended December 31, 2009 and 2008
Comparative data relating to our revenue and operating expenses by equipment type are listed below.
Operating income in 2009 decreased $7.0 million, or less than 1%, compared to 2008. During 2009, our contracted revenue backlog allowed us to partially mitigate the impact of the global economic recession on our business. Despite the downturn in the market, our contract drilling revenues increased $60.2 million in 2009 compared to 2008. The Ocean Monarch, which began service in mid-March 2009 after completing a major upgrade, generated revenues of $124.5 million during 2009. Our two new-build jack-up rigs, the Ocean Shield and Ocean Scepter, contributed additional revenues of $90.1 million during 2009 compared to 2008. However, our operating results were negatively impacted by ready-stacking of the Ocean Star, Ocean Victory, Ocean Guardian and Ocean Scepter for extended periods and the cold stacking of our three mat-supported GOM jack-up rigs. The Ocean Bounty completed its contract offshore Australia in the third quarter of 2009 and is currently being prepared for cold-stacking in Malaysia. In addition, the international jack-up market, which had remained strong throughout the majority of 2008, continued to be affected by softening demand and reduced dayrates during 2009.
Total contract drilling expenses in 2009 increased $38.8 million, or 3% compared to 2008. Operating costs during 2009 include normal operating costs for the upgraded Ocean Monarch and a full year of operating costs for our two new-build jack-ups.
Depreciation expense increased $59.0 million to $346.4 million during 2009, or 21% compared to 2008, due to a higher depreciable asset base for 2009. Depreciation expense for 2009 included depreciation associated with our capital additions in 2008 and 2009, including the Ocean Shield, Ocean Scepter and Ocean Monarch, which were all placed in service at various times during 2008. Depreciation expense for 2009 also included depreciation of the newly acquired Ocean Courage. See “-Sources of Liquidity and Capital Resources - Liquidity and Capital Requirements - Capital Expenditures.”
High-Specification Floaters.
GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $108.2 million during 2009 compared to 2008. Excluding the Ocean Monarch, our GOM fleet had approximately 700 fewer rig operating days in 2009, compared to the prior year, resulting in a $283.7 million reduction in revenues generated by the fleet in 2009. The decrease in utilization is attributable to incremental downtime associated with contract preparation activities and subsequent relocation out of the GOM of two of our high-specification floaters, the Ocean Quest (to Brazil late in the first quarter of 2009) and the Ocean Valiant (to Angola during the third quarter of 2009) and scheduled surveys and related repairs. In addition, two of our rigs were ready stacked for a total of 245 days in 2009 compared to zero ready-stack days in 2008.
Average operating revenue per day for our high-specification floaters in this market (excluding the Ocean Monarch) increased to $417,100 in 2009 compared to $394,100 in 2008, resulting in the generation of additional revenues of $51.1 million.
Operating costs for our high-specification floaters in the GOM increased by $26.1 million in 2009 compared to 2008 to $250.0 million. The overall increase in operating costs in 2009 was primarily due to higher survey, repair and mobilization costs associated with a special survey for the Ocean America. These cost increases were partially offset by lower operating costs in the region for the Ocean Quest and Ocean Valiant, which we relocated to Brazil and Angola, respectively.
The Ocean Monarch, which began operating in the GOM late in the first quarter of 2009, generated revenues and incurred operating expenses, including the amortization of deferred mobilization costs, of $124.5 million and $28.1 million, respectively.
Australia/Asia/Middle East. During 2009, our high-specification rig operating offshore Malaysia, the Ocean Rover, generated $84.3 million in additional revenues compared to 2008 primarily due to an increase in average operating revenue per day from $237,200 during 2008 to $433,700 during 2009 ($69.7 million). Utilization increased in 2009 compared to 2008, when the rig had 67 days of scheduled downtime for a special survey and related repairs, resulting in the generation of $14.6 million in incremental revenues.
Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in the third quarter of 2009 and generated revenues and incurred operating expenses of $66.2 million and $14.0 million, respectively.
South America. Revenues earned by our high-specification floaters operating offshore Brazil in 2009 increased $16.3 million compared to 2008. The Ocean Quest, which we relocated from the GOM late in the first quarter of 2009, generated additional revenues in 2009 of $90.3 million compared to 2008. Increased utilization in 2009 of the Ocean Clipper, which experienced significant downtime during 2008 for a survey and unplanned repairs to its propulsion system, generated incremental revenues of $17.3 million compared to 2008. However, total revenues generated in the region were negatively impacted by a decline in average operating revenue per day for the Ocean Alliance from $443,600 in 2008 to $187,200 in 2009, resulting in an $84.8 million reduction in revenues.
Contract drilling expense for our operations in Brazil increased slightly in 2009 by $0.5 million compared to 2008, primarily due to the inclusion of normal operating costs for the Ocean Quest partially offset by a reduction in costs attributable to a 2008 survey of the Ocean Clipper and repairs to its propulsion system.
Intermediate Semisubmersibles.
GOM. Revenues generated by our intermediate semisubmersible fleet operating in the GOM in 2009 decreased $2.7 million compared to 2008. The decrease in revenues is primarily due to a decrease in operating dayrate earned by the Ocean Saratoga in 2009 compared to 2008 ($20.8 million). The Ocean Ambassador, which relocated to the GOM from Mexico in the second quarter of 2008, earned incremental revenues of $18.9 million in the GOM in 2009 prior to its relocation to the Brazil market late in the second quarter of 2009.
During 2008, we had three rigs at various times either operating or undergoing surveys or shipyard projects in the GOM compared with only two rigs operating in the GOM for all or part of 2009. The decrease in the number of rigs in the GOM between 2008 and 2009, combined with the absence of survey-related costs in 2009, resulted in a $12.7 million reduction in operating costs in the region compared to the prior year.
Mexico. Revenues generated and contract drilling expense incurred by our intermediate semisubmersibles operating offshore Mexico decreased $3.1 million and $7.4 million, respectively, during 2009 compared to 2008, primarily due to the relocation of the Ocean Ambassador to the GOM, which resulted in a reduction in 2009 revenues and operating expenses of $13.2 million and $8.0 million, respectively. The decline in 2009 revenues was partially offset by an increase in average operating revenue per day in 2009 compared to 2008 for both of our intermediate semisubmersibles operating for PEMEX as a result of an unfavorable reserve for disputed downtime recorded in December 2008.
Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region increased $28.0 million in 2009 compared to 2008. An increase in average operating revenue per day from $306,600 in 2008 to $333,700 in 2009 generated additional revenues of $41.6 million in 2009.
Average utilization of our intermediate semisubmersible fleet in the region remained constant at 87% for both 2008 and 2009; however, downtime incurred in 2009, combined with reduced dayrates earned by the individual rigs, resulted in a $9.1 million reduction in 2009 revenues compared to 2008. The Ocean Bounty was stacked after completion of its contract offshore Australia at the beginning of the third quarter of 2009, resulting in a $40.6 million reduction in revenues compared to 2008. The negative impact on revenues from stacking the Ocean Bounty was partially offset by an increase in rig operating days for the Ocean Patriot and Ocean General that resulted in the generation of $34.6 million in incremental revenues during 2009.
Contract drilling expense for the Australia/Asia/Middle East region decreased $21.5 million in 2009 compared to 2008, primarily due to the absence of costs associated with the 2008 special surveys of the Ocean Patriot and Ocean General and reduced costs for the Ocean Bounty, which completed drilling operations offshore Australia in July 2009.
Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $36.4 million in 2009 compared to 2008. Our North Sea fleet (both U.K. and Norwegian sectors) generated $14.8 million less in revenues in 2009 compared to 2008 due to 129 fewer rig operating days in 2009 compared to 2008. Rig operating days decreased in 2009 as a result of the early termination of a drilling contract for the Ocean Nomad and intermittent work for the Ocean Guardian prior to its departure for the Falkland Islands, partially offset by reduced downtime for the Ocean Princess, which completed its 2008 special survey in early 2009. The impact of the reduction in rig operating days was partially offset by an increase in average operating revenue per day for our North Sea fleet from $321,200 in 2008 to $344,000 in 2009.
The Ocean Lexington operated offshore Egypt during 2008 through August 2009, and in September 2009, the rig was mobilized to a shipyard in Cadiz, Spain for contract preparation activities in connection with a contract offshore Brazil. Revenues generated by the Ocean Lexington in 2009 decreased $21.6 million compared to 2008 due to 103 fewer rig operating days in 2009, partially offset by higher average operating revenue per day earned in 2009 as compared to the prior year. At December 31, 2009, the Ocean Lexington was en route to Brazil.
Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets decreased $30.2 million in 2009 compared to 2008, primarily due to lower labor and personnel related costs for our rigs operating in the North Sea, including the reversal of a previously recorded reserve for paid time off for our U.K. national employees, and reduced costs associated with regulatory surveys due to fewer rigs undergoing surveys in 2009 than in 2008. In addition, operating costs in this region decreased as a result of the relocation of the Ocean Lexington to a Spanish shipyard in September 2009.
South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $83.5 million in 2009 compared to 2008. At December 31, 2009, we had seven intermediate semisubmersible rigs operating offshore Brazil and another rig, the intermediate semisubmersible Ocean Lexington, undergoing contract modification activities and mobilizing to Brazil. During 2009, our Brazilian intermediate semisubmersible fleet logged 1,996 rig operating days and earned average operating revenue per day of $217,400 compared to 1,425 rig operating days and average operating revenue per day of $177,600 in 2008. This increase in rig operating days and average operating revenue per day for our operations offshore Brazil combined to generate additional revenues of $185.4 million in 2009 compared to 2008. During 2008, the Ocean Worker earned $101.9 million operating offshore Trinidad and Tobago prior to mobilizing to Brazil in the third quarter of 2008. The Ocean Worker did not begin drilling operations offshore Brazil until March 2009.
Contract drilling expense for our intermediate semisubmersibles operating in the South American region increased $48.3 million in 2009 compared to 2008. The increase in costs in the South American region reflects the increase in number of rigs in the region, including higher maintenance and other costs associated with customer acceptance testing and the amortization of costs associated with the mobilization of our rigs into the region, shorebase support costs and revenue-based agency fees. In addition, the increased operating costs reflect higher freight and customs charges that are inherent in operations in the region.
Jack-Ups.
GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $126.5 million during 2009 compared to 2008. Average utilization decreased from 91% in 2008 to 39% in 2009 due to a decrease in demand for rigs in the GOM, and resulted in a $90.9 million decrease in revenues. Our jack-up fleet in the GOM had 1,011 ready- and cold-stacked days during 2009 compared to 22 ready-stacked days in 2008. In addition, we relocated the Ocean Summit to Mexico for a contract with PEMEX at the beginning of the third quarter of 2009. The Ocean Tower, prior to being taken out of service due to damage sustained in a hurricane in the third quarter of 2008, generated revenues of $34.3 million in 2008.
As a result of the depressed GOM market, in 2009 we elected to cold stack and no longer actively market our three mat-supported jack-ups in this region.
Contract drilling expense for our jack-ups operating in the GOM decreased $27.1 million in 2009 compared to 2008, primarily due to significantly reduced operating costs for the Ocean Tower (prior to its sale in October 2009) and our three cold-stacked rigs. The decline in operating costs was partially offset by 2009 survey and repair costs for the Ocean Titan and Ocean Summit and demobilization costs for the Ocean Columbia associated with its relocation from Mexico to the GOM in the fourth quarter of 2009 for a shipyard project.
Mexico. Revenue and contract drilling expense generated by our jack-up rigs operating in Mexico increased $0.4 million and $4.9 million, respectively. The relatively stable revenues generated by our jack-up fleet offshore Mexico reflects incremental revenues generated by the Ocean Summit beginning in the third quarter of 2009, partly offset by a reduction in revenues generated by the Ocean Columbia, which completed its contract with PEMEX at the beginning of the fourth quarter of 2009. Revenues were further reduced, compared to 2008, due to a contract extension for the Ocean Nugget until 2011, but at a lower dayrate than it previously earned. The increase in contract drilling expense was primarily due to contract preparations and customer acceptance of the Ocean Summit, as well as the inclusion of normal operating costs, partially offset by lower operating costs for the Ocean Columbia due to its relocation to the GOM.
Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region increased $48.2 million in 2009 compared to 2008, including $57.3 million of incremental revenues earned by the Ocean Shield, which began operating in the region late in the second quarter of 2008. The Ocean Heritage, which generated $11.8 million in revenues in 2008, completed its contract offshore Qatar during the first quarter of 2008 and was relocated to Egypt in late June 2008.
Contract drilling expense in the Australia/Asia/Middle East region increased $7.9 million in 2009 compared to 2008 primarily due to the inclusion of normal operating costs for the Ocean Shield for a full year in 2009 and costs associated with a survey and shipyard project for the Ocean Sovereign. The increased costs were partially offset by the absence of operating costs for the Ocean Heritage in 2009.
Europe/Africa/Mediterranean. Revenues generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $22.6 million in 2009 compared to 2008, primarily due to an $18.2 million reduction in revenues generated by the Ocean Spur in 2009. The Ocean Spur operated offshore Egypt during both 2009 and 2008; however, average operating revenue per day for the Ocean Spur decreased to $107,700 in 2009 from $152,700 in 2008, while utilization increased to nearly 100% in 2009 compared to 91% in 2008. During 2008, we recognized a $6.5 million lump-sum demobilization fee earned by the Ocean Spur upon completion of its initial contract offshore Egypt.
The $3.8 million increase in operating expense in the region in 2009 compared to 2008 is primarily attributable to the inclusion of a full year of operating costs in 2009 for the Ocean Heritage, which relocated from Qatar in the second quarter of 2008.
South America. Our newly constructed jack-up rig, the Ocean Scepter, began operating offshore Argentina late in the third quarter of 2008. Our operations offshore Argentina generated $54.9 million in revenues and incurred $36.3 million in contract drilling expense during 2009. The Ocean Scepter completed its contract in July 2009.
Other Contract Drilling Expense.
Other contract drilling expense increased $11.1 million in 2009 compared to 2008 primarily due to an increase in labor and overhead costs associated with rig-based training and a higher usage of fleet spare parts and supplies inventories.
Bad Debt Expense.
In December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the U.K. that had entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). In December 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.
Casualty Loss.
During 2008, we wrote off certain equipment that was damaged during Hurricane Ike, including the net book value of approximately $2.6 million of the Ocean Tower’s derrick, drill floor and related equipment lost in the storm, and we accrued $3.7 million in estimated salvage costs for recovery of equipment from the ocean floor.
Gain on Disposition of Assets.
Net gain on disposition of assets in 2009 includes a $6.7 million gain on the sale of the Ocean Tower compared to aggregate net gains of $2.8 million in 2008 on the sale and disposition of miscellaneous equipment.
Interest Income.
We earned interest income of $4.5 million in 2009 compared to $11.7 million in 2008. The $7.2 million decrease in interest income is primarily the result of lower average interest-bearing cash balances during 2009 compared to 2008.
Interest Expense.
Interest expense in 2009 and 2008 relates primarily to interest accrued on our outstanding indebtedness, net of capitalized interest, and our liabilities for uncertain tax positions. During 2009, we incurred interest expense of $19.6 million related to our 5.875% Senior Notes issued in May 2009 and $6.6 million related to our 5.70% Senior Notes issued in October 2009 partially offset by a net $3.4 million reduction in accrued interest expense related to uncertain tax positions. See “ - Income Tax Expense.”. During 2008, we capitalized interest of $16.9 million related to qualifying construction projects and major upgrades that were all completed in 2008. We did not capitalize interest costs in 2009 as there were no qualifying activities during 2009.
Foreign Currency Transaction Gain (Loss).
Foreign currency transaction gains (losses) include both realized and unrealized gains and losses from the settlement of and from mark-to-market accounting for our foreign currency forward exchange, or FOREX, contracts that we have not designated as accounting hedges. Such gains and losses fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies. Prior to May 1, 2009, we did not designate any of our FOREX contracts as accounting hedges.
During 2009, we recognized net foreign currency exchange gains of $11.5 million, including $8.9 million realized and unrealized gains on 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) and net gains of $2.6 million on other foreign currency transactions. During 2008, we recognized net foreign currency exchange losses of $65.6 million, including $54.0 million in net losses on FOREX contracts ($37.2 million in net unrealized losses from mark-to-market accounting and $16.8 million in net realized losses on settlement of FOREX contracts) and other net foreign currency transaction losses of $11.6 million.
Income Tax Expense.
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. We recognized $492.2 million of tax expense on pre-tax income of $1.9 billion for the year ended December 31, 2009 compared to tax expense of $536.5 million on pre-tax income of $1.8 billion in 2008.
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. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes are provided on these earnings except to the extent that such earnings were immediately subject to U.S. federal income taxes and except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings. The effective annual tax rate of 26.3% in 2009 compared favorably to the effective annual tax rate of 29.1% in 2008 primarily because of higher earnings of DOIL in 2009 which were taxed at lower rates.
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. We recognized expense of $3.3 million and $3.4 million for uncertain tax positions in 2009 and 2008, respectively. During the year ended December 31, 2009 we recorded a net reduction to interest expense related to uncertain tax positions of $3.4 million. During the year ended December 31, 2008, we recognized $0.8 million of interest expense related to uncertain tax positions. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2009 and 2008 was $4.7 million and $1.1 million, respectively. 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. In December 2009 we received an approximately $26 million assessment from the Brazilian tax authorities for the years 2004 and 2005. 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 $7 million of expense attributable to the portion of the tax assessment we determined to be an uncertain tax position in our 2009 Consolidated Statements of Operations, of which approximately $2 million was interest related and approximately $2 million was penalty related.
Years Ended December 31, 2008 and 2007
Comparative data relating to our revenue and operating expenses by equipment type are listed below.
Demand was strong for our high-specification floaters and intermediate semisubmersible rigs in all markets and geographic regions during the first nine months of 2008, however, during the fourth quarter of 2008, the growing global economic recession became apparent in our industry and resulted in reduced demand for energy and a significant decline in crude oil prices. Because of our contracted revenue backlog, however, our results were not greatly impacted by these market conditions during the fourth quarter of 2008. The high overall utilization and historically high dayrates for our floater fleet contributed to an overall increase in our revenues of $891.9 million, or 43%, to $3.0 billion in 2008 compared to $2.1 billion in 2007.
Total contract drilling revenues in 2008 increased $970.8 million, or 39% compared to 2007, to $3.5 billion. Average realized dayrates in 2008 in many of our floater markets increased as our rigs operated under contracts at higher dayrates than those earned during 2007, which resulted in the generation of additional contract drilling revenues. However, overall revenue increases for our floater fleet were negatively impacted by the effect of
downtime associated with scheduled shipyard projects and mandatory inspections or surveys. In addition, the GOM jack-up market, which had improved in early 2008 compared to the prior year, experienced reduced demand and dayrates by the end of 2008. The international jack-up market, which had been strong throughout the majority of 2008, also began to reflect softening demand and reduced dayrates by the end of 2008. Our GOM and international jack-up fleets earned lower dayrates during 2008 compared to 2007 despite a fleet-wide increase in utilization during 2008.
Total contract drilling expense increased $181.2 million, or 18%, in 2008 compared to 2007. Overall cost increases for maintenance and repairs between the 2008 and 2007 periods reflected the impact of high, sustained utilization of our drilling units across our fleet, additional survey and related maintenance costs, contract preparation and mobilization costs, as well as the inclusion of normal operating costs for the Ocean Endeavor, Ocean Shield and Ocean Scepter. The increase in overall operating and overhead costs also reflected the impact of higher prices throughout the offshore drilling industry and its support businesses, including higher costs associated with hiring and retaining skilled personnel for our worldwide offshore fleet.
Depreciation expense increased $51.7 million to $287.4 million during 2008, or 22% compared to 2007, due to a higher depreciable asset base.
Our results during 2008 were negatively impacted by $54.0 million in losses on foreign currency forward exchange contracts not designated as accounting hedges included in “Foreign currency transaction gain (loss)”, a $31.9 million provision for bad debt expense related to one of our North Sea semisubmersible rigs that was contracted to a U.K. customer that had entered into administration under U.K. law and the recognition of a casualty loss aggregating $6.3 million in connection with damages sustained from Hurricane Ike. See “ - Overview - Casualty Loss.”
High-Specification Floaters.
GOM. Revenues generated by our high-specification floaters operating in the GOM increased $217.4 million in 2008 compared to 2007, primarily due to higher average dayrates earned during 2008 ($131.7 million). Average operating revenue per day for our rigs in this market, excluding the Ocean Endeavor, increased to $413,300 during 2008 compared to $354,400 in 2007. Excluding the Ocean Endeavor, six of our seven other high-specification semisubmersible rigs in the GOM were operating at higher dayrates in 2008 than those earned during 2007. The Ocean Endeavor began operating in the GOM during the third quarter of 2007 and generated additional revenues of $49.7 million during 2008 compared to 2007.
Average utilization for our high-specification rigs operating in the GOM, excluding the Ocean Endeavor, increased slightly from 87% in 2007 to 91% in 2008, and generated $36.0 million in additional revenues in 2008. The increase in utilization in 2008 was attributable to 88 fewer downtime days during 2008 compared to 2007 when rigs were down, primarily for regulatory inspections and repairs.
Operating costs during 2008 for our high-specification floaters in the GOM increased $17.6 million to $224.0 million (including $11.3 million in incremental operating expenses for the Ocean Endeavor) compared to 2007. Operating costs for 2008 reflected higher labor, benefits and other personnel-related costs, higher maintenance and other project costs and higher property insurance costs, partially offset by lower mobilization and other inspection related costs for these rigs compared to 2007.
Australia/Asia/Middle East. Revenues generated by the Ocean Rover, our high-specification rig operating offshore Malaysia, decreased $3.6 million in 2008 compared to 2007. The revenue decrease was primarily due to scheduled downtime (67 days) for a survey and maintenance, partially offset by the effect of a higher average dayrate earned during 2008 compared to 2007.
Contract drilling expenses for the Ocean Rover increased $8.7 million in 2008 compared to 2007 primarily due to costs associated with the rig’s 2008 survey and other maintenance and repair costs and, to a lesser extent, higher labor, benefits and other personnel-related costs.
South America. Revenues earned by our high-specification floaters operating offshore Brazil during 2008 increased $77.4 million compared to 2007. Average operating revenue per day increased from $185,300 during 2007 to $339,700 during 2008, and generated additional revenues of $92.3 million. Utilization in 2008 decreased to 81% from 92% in 2007 primarily as the result of 99 days of incremental unpaid downtime for the Ocean Clipper for a special survey and repairs to its propulsion system. The decline in utilization reduced revenues by $14.9 million in 2008.
Contract drilling expense for our operations in Brazil increased $22.7 million in 2008 compared to 2007. The increase in costs was primarily due to inspection and repair costs for the Ocean Clipper and higher revenue-based agency fees and personnel and related costs during 2008, as compared to 2007.
Intermediate Semisubmersibles.
GOM. Revenues generated during 2008 by our intermediate semisubmersible fleet operating in the GOM decreased $35.6 million compared to 2007, primarily as a result of the relocation of three of our rigs from the GOM (Ocean Voyager and Ocean New Era to Mexico and Ocean Concord to Brazil) in the fourth quarter of 2007. During 2007, these three rigs generated revenues of $128.9 million while operating in the GOM.
The negative impact on revenues of the departure of these rigs was partially offset by $65.6 million and $27.8 million in additional revenues generated by the Ocean Saratoga and the Ocean Ambassador, respectively, during 2008 compared to 2007. The additional contribution by the Ocean Saratoga was primarily due to the rig operating at a higher dayrate that began in the fourth quarter of 2007 and increased utilization during 2008 compared to 2007, when the rig was out of service for 116 days to complete a service life extension project. We relocated the Ocean Ambassador to the GOM from Mexico during the second quarter of 2008.
Contract drilling expenses in the GOM decreased by $34.4 million during 2008 compared to 2007, primarily due to the absence of operating costs for the Ocean Voyager, Ocean New Era and Ocean Concord ($47.9 million) which relocated to other markets during 2007 and costs associated with shipyard projects for the Ocean Whittington and Ocean Worker ($16.8 million) that were completed in 2007 prior to relocating these rigs to the South America region. The overall decrease in contract drilling expenses in 2008 was partially offset by the inclusion of normal operating expenses and special survey costs for the Ocean Ambassador ($21.8 million). Also included in operating expenses for 2008 was $3.2 million in maintenance and other costs associated with contract preparation activities for the Ocean Yorktown prior to its mobilization to Brazil in May 2008.
Mexico. Offshore Mexico, three of our intermediate semisubmersible rigs completed their contracts with PEMEX after the second quarter of 2007 and relocated out of the region. During the fourth quarter of 2007, we relocated two semisubmersible units, the Ocean New Era and Ocean Voyager, from the GOM to Mexico. Average operating revenue per day for our rigs working offshore Mexico increased to $277,900 for 2008 compared to $98,900 per day for 2007 primarily because these two new rigs in the region worked for PEMEX at dayrates substantially higher than average rates earned during 2007. Higher dayrates, partially offset by the net reduction in the number of rigs between periods, generated $134.6 million of additional revenues during 2008 compared to 2007.
Contract drilling expenses for the Mexico region decreased $9.5 million during 2008 compared to 2007 primarily due to the effect on operating costs of the net reduction of one rig in the region, partially offset by higher maintenance costs and revenue-based agency fees.
Australia/Asia/Middle East. Our intermediate semisubmersibles working in the Australia/Asia/Middle East region generated revenues of $395.1 million during 2008 compared to revenues of $239.2 million in 2007. The $155.9 million increase in operating revenue was primarily due to an increase in average operating revenue per day from $171,500 during 2007 to $306,600 during 2008, which generated additional revenues of $171.0 million during 2008.
Average utilization in this region decreased to 87% during 2008 from 94% during 2007, resulting in a $15.1 million reduction in revenues during 2008. The decrease in utilization was primarily the result of 170 days of scheduled downtime for special surveys and repairs for three of our rigs in this region during 2008.
Contract drilling expense for the Australia/Asia/Middle East region increased $28.5 million in 2008 compared to 2007, primarily due to inspection and related repair costs associated with special surveys during 2008. In addition, normal operating costs for the Ocean Patriot were higher during 2008 when the rig operated offshore Australia compared to operating offshore New Zealand during 2007. Operating costs in this region also reflected higher labor and personnel-related costs during 2008 compared to the prior year.
Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles in the Europe/Africa/Mediterranean region increased $117.6 million in 2008 compared to 2007 primarily due to higher dayrates earned by our four rigs in the North Sea (both U.K. and Norwegian sectors). Average operating revenue per day for our North Sea semisubmersibles increased from $211,500 during 2007 to $321,200 during 2008, and contributed $144.7 million in additional revenue in 2008 compared to the prior year. The increase in revenue was partially offset by the impact of 126 days of incremental downtime during 2008 primarily associated with surveys of our U.K. rigs. The decrease in utilization reduced revenues by $27.4 million during 2008 compared to 2007.
Contract drilling expense for our intermediate semisubmersible rigs in the Europe/Africa/Mediterranean markets increased $24.2 million in 2008 compared to 2007, primarily due to the inclusion of costs associated with surveys of our rigs operating in the U.K. sector of the North Sea. In addition, during 2008, all of our rigs in this market incurred higher overall costs, primarily for labor and benefits and repairs. Operating costs for 2008 included additional costs for the Ocean Vanguard which operated offshore Ireland for a portion of 2008.
South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $228.1 million during 2008 compared to 2007. During 2008, six of our rigs operated in the region compared to four rigs during 2007. Following the first quarter of 2007, we relocated the Ocean Whittington and Ocean Concord to Brazil and the Ocean Worker to Trinidad and Tobago where they generated additional aggregate revenues of $196.2 million in 2008. The Ocean Yorktown began operating in Brazil during the third quarter of 2008 and generated $30.4 million in revenues.
Operating expenses for our operations in the South American region increased $89.8 million in 2008, compared to 2007, primarily due to the inclusion of normal operating costs for two of the rigs transferred to this region ($48.1 million) and incremental operating costs for the Ocean Worker and Ocean Whittington ($38.6 million) which only operated in the South American region for a portion of 2007. Operating expenses for 2008 also reflected higher labor and other personnel-related expenses, freight and repair and maintenance costs for our other two semisubmersible rigs in this market.
Jack-Ups.
GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $32.8 million during 2008 compared to 2007, primarily due to the relocation of the Ocean King (Croatia) and the Ocean Columbia (Mexico) after the second quarter of 2007. These two rigs generated $42.1 million in revenues while operating in the GOM during 2007. In addition, average operating revenue per day, excluding the Ocean King and Ocean Columbia, decreased to $80,800 in 2008 from $90,500 during 2007 and resulted in an additional $18.3 million decrease in revenue from the prior year.
Average utilization (excluding the Ocean King and Ocean Columbia) increased from 78% during 2007 to 92% during 2008, resulting in an increase in revenues of $32.5 million. The increase in utilization was primarily due to an improvement in market conditions in the GOM during 2008 compared to 2007 that resulted in fewer ready-stack days for our jack-up fleet between wells during 2008 (22 days) compared to 2007 (306 days). However, revenues decreased $4.8 million as a result of the Ocean Tower being taken out of service due to damages sustained during Hurricane Ike in the third quarter of 2008, which partially offset the favorable effect of increased utilization in 2008.
Contract drilling expense in the GOM decreased $19.7 million during 2008 compared to 2007. The overall decrease in operating costs during 2008 was due to the absence of operating costs in the GOM for the Ocean King and Ocean Columbia ($21.8 million). The reduction in overall operating costs was partially offset by costs associated with a regulatory survey for one of our GOM jack-ups, higher labor and benefits costs and higher overhead costs for our remaining rigs in the GOM during 2008 compared to 2007.
Mexico. Revenue and contract drilling expense from our rigs operating in Mexico increased $42.6 million and $17.2 million, respectively, in 2008 compared to 2007 primarily due to the operation of the Ocean Columbia offshore Mexico, which began in the first quarter of 2008. The Ocean Columbia generated $42.0 million in revenues and incurred $17.1 million in operating expenses during 2008.
Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region increased $4.1 million during 2008 compared to 2007. Our newly constructed jack-up rig, the Ocean Shield, began work offshore Malaysia during the second quarter of 2008 and generated $39.0 million in revenues during 2008. In addition, the Ocean Sovereign, which operated offshore Indonesia in 2008, generated additional revenues of $8.4 million due to an increase in the operating dayrate earned by the rig beginning late in the second quarter of 2008. These favorable contributions to revenue in the region were partially offset by a decrease in revenue generated by the Ocean Heritage, which was ready-stacked in a shipyard in Qatar from March 2008 through late June 2008 until it was subsequently relocated out of the region to Egypt.
Contract drilling expense in the Australia/Asia/Middle East region increased by $14.0 million in 2008 compared to 2007 primarily due to the inclusion of normal operating costs for the Ocean Shield and higher labor, benefits, repair and other operating costs for the Ocean Sovereign. These cost increases were partially offset by the absence of operating costs for the Ocean Heritage due to its relocation to Egypt.
Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region increased $42.8 million in 2008 compared to 2007. The Ocean King, operating under a two-year bareboat charter offshore Croatia that began in the third quarter of 2007, generated revenues of $37.8 million during 2008. In addition, the Ocean Heritage, which relocated to Egypt during the third quarter of 2008, generated $17.0 million of revenues in the region.
Revenues were negatively impacted by the Ocean Spur, which operated offshore Egypt all of 2008 and in both Tunisia and Egypt in 2007. The Ocean Spur generated $12.0 million less in revenues during 2008 compared to 2007, primarily due to the recognition of other operating revenues associated with its contract offshore Tunisia during 2007.
Contract drilling expense in the Europe/Africa/Mediterranean region increased by $15.6 million in 2008 compared to 2007 primarily due to the inclusion of normal operating costs for the Ocean Heritage that began in the third quarter of 2008 and, to a lesser extent, operating expenses associated with the Ocean King’s bareboat charter for the entire 2008 period.
South America. Our newly constructed jack-up rig, the Ocean Scepter, began operating offshore Argentina during the third quarter of 2008 and generated $22.1 million in revenues and incurred $14.3 million in contract drilling expenses during 2008.
Other Contract Drilling.
Other contract drilling expenses decreased $7.8 million during 2008 compared to 2007 primarily due to insurance proceeds received in 2008 related to claims filed in connection with the 2005 Hurricane Katrina. These costs had previously been expensed due to uncertainty of recovery from insurance.
Depreciation.
Depreciation expense increased $51.7 million to $287.4 million in 2008 compared to $235.7 million in 2007 primarily due to depreciation associated with capital additions in 2007 and 2008, which included a partial year’s depreciation of our two newly constructed jack-ups, the Ocean Shield and Ocean Scepter.
General and Administrative Expense.
We incurred general and administrative expense of $60.1 million in 2008 compared to $53.5 million in 2007. The $6.7 million increase in overhead costs between the periods was primarily due to an increase in payroll costs as a result of higher compensation and staffing increases, travel and related costs and engineering and tax consulting fees. These cost increases were partially offset by a reduction in legal fees due to a 2008 insurance reimbursement related to certain litigation.
Bad Debt Expense.
We recorded a provision for bad debt expense of $31.9 million in 2008 related to one of our North Sea semisubmersible rigs contracted to a U.K. customer that entered into administration under U.K. law.
Casualty Loss.
During September 2008, one of our jack-up rigs, the Ocean Tower, sustained significant damage during Hurricane Ike. As a result of this damage, we wrote off the net book value of the Ocean Tower’s derrick, drill floor and related equipment lost in the storm of approximately $2.6 million and accrued $3.7 million in estimated salvage costs for recovery of equipment from the ocean floor.
Gain on Disposition of Assets.
We recognized a net gain of $2.8 million on the sale and disposition of assets in 2008 compared to a net gain of $8.6 million in 2007 primarily for the recognition of gains on insurance settlements and from sales of used equipment.
Interest Income.
Our interest income decreased $21.8 million to $11.7 million in 2008 from $33.6 million in 2007, primarily due to lower interest rates earned on our invested cash balances in 2008 compared to 2007.
Interest Expense.
We recorded interest expense of $10.1 million in 2008 compared to $21.9 million in 2007. Interest expense in 2007 included $9.2 million in debt issuance costs that we wrote off in connection with conversions during the period of our 1.5% Convertible Senior Debentures Due 2031 and our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, into shares of our common stock. We wrote off $84,000 in debt issuance costs during 2008 related to conversions during the year.
Foreign Currency Transaction Gain (Loss).
Foreign currency transaction gains (losses) include gains and losses from the settlement of foreign currency forward exchange contracts not designated as accounting hedges and fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies. During 2008, we recognized net foreign currency exchange losses of $65.6 million, including $54.0 million in net losses on foreign currency forward exchange contracts ($37.2 million in net unrealized losses resulting from mark-to-market accounting on our open positions at December 31, 2008 and $16.8 million in net realized losses on settlement of forward contracts). During 2007, we recognized net foreign currency exchange gains of $2.9 million.
Income Tax Expense.
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. We recognized $536.5 million of tax expense on pre-tax income of $1.8 billion for the year ended December 31, 2008 compared to tax expense of $398.9 million on a pre-tax income of $1.2 billion in 2007.
Certain of our international rigs are owned and operated, directly or indirectly, by DOIL, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes were provided on these earnings in years subsequent to 2002 except to the extent that such earnings were immediately subject to U.S. federal income taxes. In December 2007, DOIL made a non-recurring distribution of $850.0 million to its U.S. parent, a portion of which consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. We recognized $58.6 million of U.S. federal income tax expense in 2007 as a result of the distribution. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except for the earnings of
DEAL, a wholly-owned subsidiary of DOIL formed in December 2008. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings.
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. We recognized expense of $3.4 million and $3.7 million for uncertain tax positions in 2008 and 2007, respectively. During the years ended December 31, 2008 and 2007, we recognized $0.8 million and $1.7 million of interest expense related to uncertain tax positions, respectively. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2008 and 2007 was $1.1 million and $0.8 million, respectively.
Sources of Liquidity and Capital Resources
Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. We may also make use of our $285 million credit facility for cash liquidity. See “- $285 Million Revolving Credit Facility.”
At December 31, 2009, we had $376.4 million in “Cash and cash equivalents” and $400.9 million in “Investments and marketable securities,” representing our investment of cash available for current operations.
Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our customers to weather the continuing global financial crisis and restrictions in the credit market, as well as the volatility in energy prices. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may appear 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. If a potential customer is unable to obtain an adequate level of credit, it may preclude us from doing business with that potential customer. The global financial crisis could also have an impact on our existing customers, causing them to fail to meet their obligations to us or attempt to renegotiate existing contract terms. In addition, we may offer inducements to our customers to extend existing contracts. For example, during the second half of 2009, we reached an agreement with one of our customers in the GOM for a second one-year contract extension. In exchange for the extension, we agreed to a varying dayrate structure which provides for lower dayrates during the four-month period when the rig is restricted from operating during hurricane season, and higher dayrates at other times.
During the second quarter of 2009, one of our customers sought short-term financial relief with respect to an existing contractual agreement with us for a six-well, one-year minimum contract term, program that began in May 2009. As a result, we agreed to amend our existing contract with this customer, and in consideration of this amendment, we are to receive a $20,000 per day increase in the total contractual operating dayrate, to a total of $560,000 per day, for a minimum of the first 240 days of the initial one-year contract. Under the terms of the amended agreement, the customer is obligated to pay us $75,000 per day in accordance with our normal credit terms (due 30 days after receipt of invoice). The remainder of the dayrate for the six-well program (minimum of 240 days) will be paid through the conveyance of a 27% net profits interest, or NPI, in a minimum of five developmental oil-and-gas producing properties covering six wells owned by the customer. Based on the current production payout estimate, we anticipate that the first payment from the conveyance of the NPI will commence in early 2010. Payments of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices. The residual days under the initial one-year (365 day) contract will be deferred until the fourth quarter of 2011 when the customer will utilize the rig at the originally contracted dayrate and provide a 25% up-front escrow payment with the remaining 75% to be paid in accordance with normal credit terms. At December 31, 2009, the portion of our trade receivable that is expected to be paid from the NPI was $70.5 million and is presented as “Accounts Receivable” in our Consolidated Balance Sheets included in Item 8 of this report.
These external factors which affect our cash flows from operations are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “- Overview - Industry Conditions,” “ - Forward-Looking Statements” and “Risk Factors” in Item 1A of this report.
$285 Million Revolving Credit Facility. We maintain a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.
Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
Based on our current credit ratings at December 31, 2009, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2009, there were no loans outstanding under the Credit Facility; however $63.3 million in letters of credit were issued and outstanding under the Credit Facility.
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 and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet both our working capital requirements and our capital commitments over the next twelve months; however, we will 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. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.
Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2009.
The above table excludes foreign currency forward exchange contracts in the aggregate notional amount of $114.0 million outstanding at December 31, 2009. 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, 2009 and December 31, 2008, 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, 2009 and December 31, 2008, 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.
Loans under our $285 million syndicated, senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) LIBOR plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of December 31, 2009 and 2008, there were no loans outstanding under the Credit Facility (however, as of December 31, 2009 and 2008, $63.3 million and $58.1 million, respectively, in letters of credit were issued and outstanding under the Credit Facility).
Our long-term debt, as of December 31, 2009 and December 31, 2008, is denominated in U.S. dollars. Our debt has been primarily 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 $136.2 million and $20.9 million as of December 31, 2009 and 2008, respectively. A 100-basis point decrease would result in an increase in market value of $121.3 million and $21.6 million as of December 31, 2009 and 2008, 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 foreign currency forward exchange contracts in the normal course of business. These contracts may require 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 outstanding contracts, is the average spot rate for the contract period. As of December 31, 2009, we had foreign currency exchange contracts outstanding, in the aggregate notional amount of $114.0 million, consisting of $37.6 million in Australian dollars,
$42.6 million in Brazilian reais, $20.7 million in British pounds sterling, $5.3 million in Mexican pesos and $7.8 million in Norwegian kroner. These contracts settle at various times through September 2010. At December 31, 2009, we have presented the fair value of our outstanding foreign currency forward exchange contracts as a current asset of $2.6 million in “Prepaid expenses and other current assets” and a current liability of $(0.2) 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, 2009 and 2008, 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, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and the financial statement schedule 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 the Company as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
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, 2009, 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 23, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2010
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, 2009, 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 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, 2009, 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, 2009 of the Company and our report dated February 23, 2010 expressed an unqualified opinion on those financial statements and the financial statement schedule.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2010
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 current fleet of 47 offshore rigs consisting of 32 semisubmersibles, 14 jack-ups and one drillship. 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.
Our management has evaluated subsequent events through the time of our filing with the Securities and Exchange Commission on February 23, 2010, the date on which we issued our financial statements.
As of February 19, 2010, 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 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.
Restatement of Convertible Debt Securities Which May Be Partially or Fully Settled in Cash
Prior to January 1, 2009, convertible debt securities that may be settled by the issuer fully or partially in cash were not required to be separated into a debt and equity component. Subsequent to that date, GAAP requires that all convertible debt securities that may be settled by the issuer fully or partially in cash be separated into a debt and an equity component. The proceeds of the issuance are first allocated to the debt portion based on the estimated fair value of a similar debt issue without a conversion option; the remaining proceeds are allocated to equity. The bifurcation requirement applies to both newly issued debt and debt issuances outstanding for any time during the accounting periods for which financial statements are presented and is to be retrospectively applied to all past periods presented.
Both our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, and our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, have such conversion features as previously described. Our other outstanding indebtedness does not have similar conversion features. See Note 10.
We have retrospectively applied the bifurcation requirement to our Zero Coupon Debentures and 1.5% Debentures and, accordingly, have adjusted our consolidated financial statements and notes thereto to reflect this change as of January 1, 2007, the earliest period presented. The effect of bifurcation on our Consolidated Balance Sheets was as follows:
The carrying amounts of the liability and equity components of the debentures at December 31, 2009 and December 31, 2008 were as follows:
Zero Coupon Debentures
1.5% Debentures
Total
December 31,
December 31,
December 31,
(In thousands)
Carrying amount of liability component of debt issue
$ 4,179
$ 4,036
$ -
$ -
$ 4,179
$ 4,036
Carrying amount of equity component of debt issue
$ 48,997
$ 48,997
$ 62,701
$ 62,701
$ 111,698
$ 111,698
Debt discounts related to our Zero Coupon Debentures and 1.5% Debentures were fully amortized in 2005 and 2007, respectively. Consequently, the adoption of the bifurcation requirement had no effect on the carrying amount of our Zero Coupon Debentures at December 31, 2009 and December 31, 2008. We redeemed our then outstanding 1.5% Debentures in full in April 2008.
The effect of bifurcation of our Zero Coupon Debentures and 1.5% Debentures on our Consolidated Statements of Operations was as follows:
Interest expense (net of capitalized interest) for our Zero Coupon Debentures and 1.5% Debentures related to their contractual coupon rate (including amortization of the remaining debt discount on our 1.5% Debentures) was as follows:
For the Year Ended December 31,
(In thousands)
Zero Coupon Debentures
$
$
$
1.5% Debentures
-
5,354
The effective interest rate for our Zero Coupon Debentures and 1.5% Debentures was 3.63% and 1.6%, respectively, in each year for which interest expense has been presented in the table above.
The effect of accounting for the bifurcation of our Zero Coupon Debentures and 1.5% Debentures on previously reported basic and diluted earnings per share, or EPS, is summarized below.
Other Reclassifications
Previously reported amounts for “Reimbursable expenses” in our Consolidated Statements of Operations for the year ended December 31, 2007 have been adjusted to include $7.4 million in reimbursable catering expense to conform to the current presentation. These amounts were previously reported as “Contract drilling” expense in our Consolidated Statements of Operations. This reclassification had no effect on total operating expenses, operating income or net income for the year ended December 31, 2007.
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 gains (losses)” 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).”
Derivative Financial Instruments
Our derivative financial instruments include foreign currency forward exchange contracts. See Notes 5 and 6.
Supplementary Cash Flow Information
We paid interest totaling $39.5 million, $25.1 million and $25.3 million on long-term debt for the years ended December 31, 2009, 2008 and 2007, respectively.
We paid $176.2 million, $120.7 million and $31.7 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2009, 2008 and 2007, respectively. We paid $252.4 million, $393.2 million and $299.0 million in U.S. federal income taxes during the years ended December 31, 2009, 2008 and 2007, respectively. We received a refund of $25,000 in U.S. income taxes during the year ended December 31, 2007. We paid state income taxes of $0.2 million and $0.6 million during the years ended December 31, 2009 and 2007, respectively, and received a $0.1 million refund of state income tax during the year ended December 31, 2008.
Cash payments for capital expenditures for the year ended December 31, 2009 included $59.4 million of capital expenditures that were accrued but unpaid at December 31, 2008. Cash payments for capital expenditures for the year ended December 31, 2008 included $43.0 million of capital expenditures that were accrued but unpaid at December 31, 2007. Capital expenditures that were accrued but not paid as of December 31, 2009 totaled $64.9 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2009.
We recorded income tax benefits of $1.0 million, $1.5 million and $2.7 million related to the exercise of employee stock options in 2009, 2008 and 2007, respectively.
During 2008, holders of $33,000 in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. Also during 2008, the holders of $3.5 million in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 10.
Assets Held For Sale
At December 31, 2008, we had transferred the $32.2 million net book value of the Ocean Tower to “Assets held for sale” in our Consolidated Balance Sheets. In December 2008, we entered into an agreement to sell the rig, which was damaged during Hurricane Ike (see Note 16), at a price in excess of its carrying value. In connection with the execution of the sales agreement, we received an initial deposit of $3.5 million from the purchaser which we recorded in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2008. The sale of the Ocean Tower was completed on October 26, 2009, and we recognized a $6.7 million gain on the transaction.
Drilling and Other Property and Equipment
Our drilling and other property and equipment are carried at cost. We charge maintenance and routine repairs to income currently while replacements and betterments, which meet certain criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade 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. 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. For the two years ended December 31, 2008 and 2007, we capitalized interest on qualifying expenditures related to the upgrades of the Ocean Endeavor and Ocean Monarch for ultra-deepwater service and the construction of two jack-up rigs, the Ocean Shield and Ocean Scepter, through the date of each project’s completion. The upgrades of the Ocean Endeavor and Ocean Monarch were completed in March 2007 and December 2008, respectively. Construction of the Ocean Shield and Ocean Scepter was completed in May 2008 and August 2008, respectively.
A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:
We did not capitalize any interest cost during the year ended December 31, 2009 as there were no qualifying expenditures during the period.
Asset Retirement Obligations
At December 31, 2009 and 2008, 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 new-build 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, ready-stacked or cold-stacked; and
•
salvage value for each rig.
Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates. We also 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), or alternatively the impact of a 5% reduction in utilization (again holding all other assumptions and estimates in the model constant) as part of our analysis.
2009. As of December 31, 2009, we had cold-stacked our three mat-supported jack-up rigs and were in the process of cold-stacking an intermediate semisubmersible drilling rig in Malaysia. We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we have concluded that these four rigs were not subject to impairment at December 31, 2009.
At December 31, 2009, the remaining rigs in our fleet were currently working under contract, mobilizing to new locations or being actively marketed. We do not believe that current circumstances indicate that there was an impairment of these 43 rigs at December 31, 2009.
2008. As of December 31, 2008, all of our drilling rigs were either under contract, in shipyards for surveys or contract modifications or, as in the case of the upgraded Ocean Monarch, mobilizing to the U.S., except for two jack-up rigs. One of these idle units, the Ocean Tower, was damaged during Hurricane Ike in September 2008 (see Note 16), and was presented as “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2008. The rig was subsequently sold in October 2009 for a net gain of $6.7 million. At December 31, 2008, the second of our idle rigs was ready-stacked while waiting to begin drilling operations in early January 2009. Consequently, we determined that an impairment test of our drilling equipment was not needed as all of our drilling units were being marketed at the time, and we did not have any cold-stacked rigs at December 31, 2008. We have concluded that circumstances at that time did not indicate that there was an impairment of our property and equipment.
2007. As of December 31, 2007, all of our drilling rigs were either under contract or were in shipyards for surveys, contract modifications or major upgrade, except for two of our jack-up drilling rigs located in the U.S. Gulf of Mexico. At December 31, 2007, one of these idle units was under contract but waiting to begin drilling operations while the other unit was being actively marketed. Consequently, we determined that an impairment test of our drilling equipment was not needed as we were currently marketing all of our drilling units at the time. We did not have any cold-stacked rigs at December 31, 2007. We have concluded that circumstances at that time did not indicate that there was an impairment of our property and equipment.
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 6.
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. Interest expense for 2008 included $84,000 in debt issuance costs that we wrote off in connection with the conversions and final redemption of our 1.5% Debentures during 2008. Interest expense for the years ended December 31, 2007 included $9.2 million in debt issuance costs that we wrote off in connection with conversions of our 1.5% Debentures and Zero Coupon Debentures into shares of our common stock. See Note 10.
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.
Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned or operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activity. In December 2007, this subsidiary made a non-recurring distribution to its U.S. parent. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign activities, except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of Diamond Offshore International Limited formed in December 2008. It is our intention to repatriate the earnings of Diamond East Asia Limited and, accordingly, U.S. income taxes are recorded on its earnings.
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 14.
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 2009, 2008 or 2007.
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, 2009, 2008 and 2007 includes net income (loss) and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges, as well as an adjustment related to the termination of our pension plan in 2007. See Note 11.
Foreign Currency
Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses, including gains and losses from the settlement of foreign currency forward exchange, or FOREX, contracts not designated as accounting hedges, are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
For the years ended December 31, 2009, 2008 and 2007, we recognized net foreign currency gains (losses) of $11.5 million, $(65.6) million and $2.9 million, respectively. See Note 5.
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 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 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.
Recent Accounting Pronouncements
The Financial Standards Accounting Board, or FASB, has issued Accounting Standards Update 2010-06, or ASU 2010-06, that describes amendments to FASB Accounting Standards Codification Subtopic 820-10 relating to fair value measurements. ASU 2010-06 amends the original codification to require additional disclosures regarding transfers in and out of Level 1 and Level 2 fair value measurements and activity within Level 3 fair value measurements. In addition, ASU 2010-06 clarifies existing disclosure requirements regarding the level of disaggregation of classes of assets and liabilities for which fair value measurements are disclosed, as well as disclosures about inputs and valuation techniques. This amendment is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain disclosures regarding Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010. Early adoption is permitted. We are currently reviewing the effect of these amendments; however, we do not expect the application of ASU 2010-06 to have a material effect on our results of operations or financial position.
2. 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, 2009, 2008 and 2007 was $6.5 million, $6.3 million and $4.5 million, respectively. Tax benefits recognized for the years ended December 31, 2009, 2008 and 2007 related thereto were $2.1 million, $2.1 million and $1.5 million, respectively.
The fair value of options and SARs granted under the Stock Plan during each of the years ended December 31, 2009, 2008 and 2007 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, 2009 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, 2009, 2008 and 2007 were $28.46, $33.73 and $36.80, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2009, 2008 and 2007 was $1.5 million, $6.3 million and $20.6 million, respectively. The total fair value of awards vested during the years ended December 31, 2009, 2008 and 2007 was $6.6 million, $5.3 million and $3.6 million, respectively. As of December 31, 2009 there was $9.8 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 2.37 years.
3. Earnings Per Share
A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
Our computation of diluted EPS for the year ended December 31, 2009 excludes stock options representing 8,291 shares of common stock and 413,610 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.
Our computation of diluted EPS for the year ended December 31, 2008 excludes stock options representing 3,362 shares of common stock and 254,821 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.
Our computation of diluted EPS for the year ended December 31, 2007 excludes stock options representing 22,937 shares of common stock and 154,119 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period.
4. Marketable Securities
We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations.
Our other 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:
5. 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/losses on foreign currency expenditures in the future. 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.
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 losses and gains on
the qualifying hedged positions. For derivative contracts entered into prior to May 2009, we did not seek hedge accounting treatment under GAAP. Accordingly, prior to May 2009, all adjustments to record the carrying value of our derivative financial instruments at fair value were reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
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.
Beginning in May 2009, we began a hedging strategy and designated certain of our qualifying FOREX contracts as cash flow hedges. These 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 is recorded as a component of “Accumulated other comprehensive gains,” or AOCG, in our Consolidated Financial Statements. The effective portion of the cash flow hedge will remain in AOCG 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. Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value are recorded as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
Realized gains or losses upon settlement of derivative contracts designated as cash flow hedges are reported as a component of “Contract drilling” 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.
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. During the years ended December 31, 2008 and 2007, we settled FOREX contracts with an aggregate notional value of approximately $538.8 million and $144.4 million, respectively, none of which were designated as accounting hedges.
The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as hedging instruments for the years ended December 31, 2009, 2008 and 2007.
For the Years Ended December 31,
Location of Gain (Loss) Recognized in Income
(In thousands)
Contract drilling expense
$ 8,895
$ -
$ -
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, 2009, 2008 and 2007.
For the Years Ended December 31,
Location of Gain (Loss) Recognized in Income
(In thousands)
Foreign currency transaction gain (loss)
$ 8,856
$ (54,010 )
$ 5,423
The amount presented in the table above for the year ended December 31, 2009 includes net unrealized gains aggregating $37.3 million to record the carrying value of our derivative financial instruments to their fair value. The amounts presented in the table above include net unrealized losses of approximately $(37.2) million and $(2.7) million for the years ended December 31, 2008 and 2007, respectively, to record the carrying value of our derivative financial instruments to their fair value.
As of December 31, 2009, we had FOREX contracts outstanding in the aggregate notional amount of $114.0 million, consisting of $37.6 million in Australian dollars, $42.6 million in Brazilian reais, $20.7 million in British pounds sterling, $5.3 million in Mexican pesos and $7.8 million in Norwegian kroner. These contracts generally settle monthly through September 2010. As of December 31, 2009, all outstanding derivative contracts had been designated as cash flow hedges. See Note 6.
The following table presents the fair values of our derivative financial instruments at December 31, 2009.
Assets
Liabilities
Balance Sheet
Balance Sheet
Location
Fair Value
Location
Fair Value
(In thousands)
(In thousands)
Derivatives designated as hedging instruments:
FOREX contracts
Prepaid expenses and other current assets
$ 2,634
Accrued liabilities
$(230)
The following table presents the fair values of our derivative financial instruments at December 31, 2008.
Assets
Liabilities
Balance Sheet
Balance Sheet
Location
Fair Value
Location
Fair Value
(In thousands)
(In thousands)
Derivatives not designated as hedging instruments:
FOREX contracts
Prepaid expenses and other current assets
$ -
Accrued liabilities
$(37,301)
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 year ended December 31, 2009.
Location of Gain
Amount of
Location of
Recognized in Income
Amount of (Loss)
Pre-Tax Gain
Pre-Tax Gain
Amount of
on Derivative
Recognized in Income on
Recognized in
Reclassified from
Pre-Tax Gain
(Ineffective Portion
Derivative (Ineffective
AOCG on
AOCG into
Reclassified from
and Amount Excluded
Portion and Amount
Derivative
Income (Effective
AOCG into Income
from Effectiveness
Excluded from
(Effective Portion)
Portion)
(Effective Portion)
Testing)
Effectiveness Testing)
(In thousands)
(In thousands)
(In thousands)
$9,838
Contract drilling expense
$7,434
Foreign currency transaction gain
$-
As of December 31, 2009, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $2.4 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.
6. 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 place our excess cash investments in high quality 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.
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. 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.
During the second quarter of 2009, one of our customers sought short-term financial relief with respect to an existing contractual agreement with us for a six-well, one-year minimum contract term, program that began in May 2009. As a result, we agreed to amend our existing contract with this customer, and in consideration of this amendment, we are to receive a $20,000 per day increase in the total contractual operating dayrate, to a total of $560,000 per day, for a minimum of the first 240 days of the initial one-year contract. Under the terms of the amended agreement, the customer is obligated to pay us $75,000 per day in accordance with our normal credit terms (due 30 days after receipt of invoice). The remainder of the dayrate for the six-well program (minimum of 240 days) will be paid through the conveyance of a 27% net profits interest, or NPI, in a minimum of five developmental oil-and-gas producing properties covering six wells owned by the customer. Based on the current production payout estimate, we anticipate that the first payment from the conveyance of the NPI will commence in early 2010. Payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.
At December 31, 2009, the $70.5 million portion of this trade receivable that is expected to be paid from the NPI, is presented as “Accounts Receivable” in our Consolidated Balance Sheets. At December 31, 2009, we believe that collectability of the amount owed pursuant to the NPI arrangement is reasonably assured. During the year ended December 31, 2009, we earned a dayrate totaling $560,000 per day and recognized revenue and interest income per day of $540,000 and $20,000, respectively.
Historically, we have not experienced significant losses on our trade receivables. However, in December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the United Kingdom, or U.K., that had entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). In December 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. We also provide allowances for potential credit losses when necessary. No additional allowances were deemed necessary for the years presented.
A majority 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.
Fair Values
The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts 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, 2009 and 2008, 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:
•
Cash and cash equivalents - The carrying amounts approximate fair value because of the short maturity of these instruments.
•
Marketable securities - The fair values of the debt securities, including mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2009 and 2008, respectively.
•
Accounts receivable and accounts payable - The carrying amounts approximate fair value based on the nature of the instruments.
•
Forward exchange contracts - The fair value of our foreign currency forward exchange contracts is based on both quoted market prices and valuations derived from pricing models on December 31, 2009 and 2008, respectively.
•
Long-term debt - The fair value of our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, and 5.875% Senior Notes due 2019, or 5.875% Senior Notes, was based on the quoted closing market price on December 31, 2009 from brokers of these instruments. The fair value of our 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, 2009 and 2008, respectively, from brokers of these instruments. The fair value of our Zero Coupon Debentures was based on the closing market price of our common stock on December 31, 2009 and 2008, respectively, and the stated conversion rate for these debentures.
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 and U.S. Treasury Bills. Our Level 1 assets at December 31, 2009 consisted of cash held in money market funds of $337.8 million and investments in U.S. Treasury Bills of $400.0 million. Our Level 1 assets at December 31, 2008 consisted of cash held in money market funds of $300.5 million and investments in U.S. Treasury Bills of $399.5 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 mortgage-backed securities and over-the-counter foreign currency forward exchange contracts that are valued using a model-derived valuation technique.
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.
Assets measured at fair value on a recurring basis are summarized below:
7. Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of the following:
8. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
During 2009, we purchased two new-build, dynamically positioned, semisubmersible drilling rigs, the Ocean Courage and Ocean Valor, for an aggregate cost of $950.0 million, exclusive of final commissioning, initial mobilization, drill string and other necessary capital spares.
9. Accrued Liabilities
Accrued liabilities consist of the following:
10. Long-Term Debt
Long-term debt consists of the following:
Certain of our long-term debt payments may be accelerated due to rights that the holders of our debt securities have to put the securities to us. The holders of our outstanding Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on June 6, 2010. See “Zero Coupon Debentures” for further discussion of the rights that the holders of these debentures have to put the securities to us.
The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2009, are as follows:
$285 Million Revolving Credit Facility
In November 2006, we entered into a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.
Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
Based on our current credit ratings at December 31, 2009, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2009, there were no loans outstanding under the Credit Facility. See Note 12 for a discussion of letters of credit issued under the Credit Facility.
5.70% Senior Notes
On October 8, 2009, we issued $500.0 million aggregate principal amount of our 5.70% Senior Notes for general corporate purposes. The 5.70% Senior Notes were issued at an offering price of 99.344% of the principal and resulted in net proceeds to us of approximately $496.7 million. We incurred issuance costs of $4.8 million related to this transaction.
These notes bear interest at 5.70% per year, payable semiannually in arrears on April 15 and October 15 of each year, beginning April 15, 2010, and mature on October 15, 2039. The 5.70% Senior Notes are 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.
5.875% Senior Notes
On May 4, 2009, we issued $500.0 million aggregate principal amount of our 5.875% Senior Notes for general corporate purposes. The 5.875% Senior Notes were issued at an offering price of 99.851% of the principal and resulted in net proceeds to us of approximately $499.3 million. We incurred issuance costs of $4.0 million related to this transaction.
These notes bear interest at 5.875% per year, payable semiannually in arrears on May 1 and November 1 of each year, and mature on May 1, 2019. The 5.875% Senior Notes are 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.
4.875% Senior Notes
Our 4.875% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year, and mature on July 1, 2015. Our 4.875% Senior Notes are 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 the 4.875% Senior 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.
5.15% Senior Notes
Our 5.15% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at 5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year, and mature on September 1, 2014. The 5.15% Senior Notes are 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 the 5.15% Senior 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.
Zero Coupon Debentures
We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, representing a yield to maturity of 3.50% per year, and they mature on June 6, 2020. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. In addition, holders may require us to purchase, for cash, all or a portion of their Zero Coupon Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to the accreted value through the date of repurchase. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.
We also have the right to redeem the Zero Coupon Debentures, in whole or in part, for a price equal to the issuance price plus accrued original issue discount through the date of redemption. Holders have the right to require us to repurchase the Zero Coupon Debentures on June 6, 2010 and June 6, 2015, at the accreted value through the date of repurchase. We may pay any such repurchase price with either cash or shares of our common stock or a combination of cash and shares of common stock.
At December 31, 2009, the aggregate accreted value of our outstanding Zero Coupon Debentures was $4.2 million and has been presented as “Current portion of long-term debt” in our Consolidated Balance Sheets. The aggregate principal amount at maturity of these outstanding debentures would be $6.0 million assuming no additional conversions or redemptions occur prior to the maturity date.
During 2008, holders of $33,000 in accreted, or carrying, value through the date of conversion of our Zero Coupon Debentures elected to convert their outstanding debentures into 430 shares of our common stock. The aggregate principal amount at maturity of our Zero Coupon Debentures converted during 2008 was $50,000. There were no conversions of our Zero Coupon Debentures to common stock during 2009.
1.5% Debentures
On April 11, 2001, we issued $460.0 million principal amount of 1.5% Debentures, which were due April 15, 2031. The 1.5% Debentures were convertible into shares of our common stock at the option of the holders of such debentures, and, during the period from January 1, 2008 to April 14, 2008, the holders of $3.5 million in aggregate principal amount of our 1.5% Debentures elected to convert their outstanding debentures into 71,144 shares of our common stock.
In addition, we had the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest. On April 15, 2008, we completed the redemption of all of our then remaining 1.5% Debentures for $73,000 in cash.
11. 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:
12. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. We have assessed each claim or exposure to determine the likelihood that the resolution of the matter might ultimately result in an adverse effect on our financial condition, results of operations and cash flows. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a reserve for the estimated loss at the time that both of these criteria are met. Our management believes that we have established adequate reserves for any liabilities that may reasonably be expected to result from these claims.
Litigation. We were a defendant in a lawsuit filed in January 2005 in the U.S. District Court for the Eastern District of Louisiana on behalf of Total E&P USA, Inc. and several oil companies alleging that our semisubmersible rig, the Ocean America, damaged a natural gas pipeline in the Gulf of Mexico during Hurricane Ivan. During the second quarter of 2009, the U.S. District Court ruled in our favor and dismissed the lawsuit. The plaintiffs initially appealed the judgment but, in November 2009, filed a motion instructing the Court to withdraw and dismiss their appeal. The Court dismissed the appeal and ordered the plaintiffs to reimburse approximately $172,000 of our costs incurred at trial.
We are one of several unrelated defendants in lawsuits filed in the Circuit Courts of the State of Mississippi 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. We expect to receive complete defense and indemnity from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. 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 adverse 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 deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. 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 reserve for personal injury claims based on our historical losses and utilizing various actuarial models. At December 31, 2009, our estimated liability for personal injury claims was $32.1 million, of which $9.2 million and $22.9 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2008, we had recorded loss reserves for personal injury claims aggregating $30.1 million, of which $9.5 million and $20.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
•
the severity of personal injuries claimed;
•
significant changes in the volume of personal injury claims;
•
the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
•
inconsistent court decisions; and
•
the risks and lack of predictability inherent in personal injury litigation.
Purchase Obligations. As of December 31, 2009, we had no 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 and equipment under operating leases, which expire at various times through the year 2013. Total rent expense amounted to $5.5 million, $5.7 million and $4.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. Future minimum rental payments under leases are approximately $1.2 million, $0.8 million, $0.2 million and nil for the years ending December 31, 2010, 2011, 2012 and 2013, respectively. There are no minimum future rental payments under leases after 2013.
Letters of Credit and Other. We were contingently liable as of December 31, 2009 in the amount of $166.6 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $63.3 million in letters of credit issued under our Credit Facility. At December 31, 2009, we had purchased eight of our outstanding bonds, totaling $103.1 million, from a related party after obtaining competitive quotes. Agreements relating to approximately $95.7 million of performance bonds can require collateral at any time. As of December 31, 2009, 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.
13. 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, $0.5 million and $0.4 million by Loews for these support functions during the years ended December 31, 2009, 2008 and 2007, 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, 2009, six performance and two appeal bonds totaling $103.1 million were outstanding. Premiums and fees associated with bonds purchased from affiliates totaled $213,000, $74,000 and $45,000 in 2009, 2008 and 2007, 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, 2009, 2008 and 2007, we paid $3.6 million, $0.5 million and $4.6 million, respectively, for the hire of such vessels and such services.
During the years ended December 31, 2009, 2008 and 2007 we made payments of $2.1 million, $2.0 million and $1.1 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
14. Income Taxes
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, 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. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes were provided on these earnings in years subsequent to 2002 except to the extent that such earnings were immediately subject to U.S. federal income taxes. In December 2007, DOIL made a non-recurring distribution of $850.0 million to its U.S. parent, a portion of which consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. We recognized $58.6 million of U.S. federal income tax expense in 2007 as a result of the distribution. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL formed in December
2008. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings.
Although we do not intend to repatriate the earnings of DOIL, these foreign earnings could become subject to U.S. federal tax if remitted, or if deemed remitted as a dividend; however, it is not practicable to estimate this tax liability.
We have certain other foreign subsidiaries for which U.S. taxes have been provided to the extent a U.S. tax liability could arise upon remittance of earnings from the foreign subsidiaries. As of December 31, 2009, we provided $24,000 for U.S. taxes attributable to undistributed earnings of the foreign subsidiaries. On actual remittance, certain countries may impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.
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)
$7.2 million and $9.4 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. See Note 7.
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, 2009 all $27.0 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 year ended December 31, 2009, we recorded a net reduction to interest expense of $3.4 million. During the years ended December 31, 2008 and 2007, we recognized $0.8 million and $1.7 million of interest expense related to uncertain tax positions, respectively. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2009, 2008 and 2007 was $4.7 million, $1.1 million and $0.8 million, respectively. Accruals for the payment of interest and penalties in our Consolidated Balance Sheets at December 31, 2009 and 2008 were $17.4 million and $16.1 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 that could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination. During 2010 certain income tax returns will no longer be subject to examination due to a lapse in the applicable statute of limitations. As a result, we anticipate that the amount of unrecognized tax benefits attributable to transfer pricing methodology will decrease by approximately $1.3 million through December 31, 2010.
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 2000 to 2008. During 2009 we reached an agreement with the U.S. Internal Revenue Service to settle the audits of the tax years 2004 through 2006 for total additional income tax expense of $55,000.
The Brazilian tax authorities are auditing our income tax returns for the periods 2000, 2004 and 2005. We received an initial audit report for tax year 2000 disallowing various deductions claimed in the tax return. 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 million for the years 2004 and 2005, including interest and penalties. 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 $7 million of expense attributable to the portion of the tax assessment we determined to be an uncertain tax position in our 2009 Consolidated Statements of Operations, of which approximately $2 million was interest related and approximately $2 million was 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 the years ended December 31, 2008 and 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. See Note 10. As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $0.5 million and $54.2 million in 2008 and 2007, respectively, which was accounted for as an increase to “Additional paid-in capital.” The reversal related to interest expense imputed on these debentures for U.S. federal income tax return purposes.
As of December 31, 2009, we had NOL carryforwards of approximately $0.2 million available to offset future taxable income. The NOL carryforwards consist entirely of losses that were acquired in our merger with Arethusa (Off-Shore) Limited, or Arethusa, in 1996. The utilization of the NOL carryforwards acquired in the Arethusa merger is limited pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, or the Code. We expect to fully utilize all of the NOL carryforwards in 2010. During 2009, we were able to utilize approximately $2.3 million of the NOL carryforwards.
15. Employee Benefit Plans
Defined Contribution Plans
We maintain defined contribution retirement plans for our U.S., 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 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, 2009, 2008 and 2007, we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the 401k Plan. Participants are fully vested immediately upon enrollment in the 401k Plan. For the years ended December 31, 2009, 2008 and 2007, our provision for contributions was $26.0 million, $23.8 million and $20.9 million, respectively.
The defined contribution retirement plan for our U.K. employees, or U.K. Plan, 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 $1.4 million, $1.7 million and $1.5 million for the years ended December 31, 2009, 2008 and 2007, respectively.
The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During 2009, 2008 and 2007 we contributed 5.00% of a participant’s defined compensation and matched 100% of the first 6% of each employee’s compensation contributed to the International Savings Plan. Our provision for contributions was $2.5 million, $2.3 million and $2.1 million for the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008 and 2007 was approximately $241,000, $222,000 and $192,000, respectively.
16. Casualty Loss
Casualty Loss
In September 2008, the Ocean Tower sustained significant damage during Hurricane Ike, which impacted the Gulf of Mexico and the upper Texas and Louisiana Gulf coasts. The Ocean Tower lost its derrick, drill floor and drill floor equipment during the hurricane. During the third quarter of 2008, we wrote off the net book value of approximately $2.6 million of the derrick, drill floor and drill floor equipment for the Ocean Tower and accrued $3.7 million in estimated salvage costs for the recovery of equipment from the ocean floor. The aggregate of these items is reflected in “Casualty loss” in our Consolidated Statements of Operations for the year ended December 31, 2008.
In December 2008, we transferred the $32.2 million net book value of the Ocean Tower to “Assets held for sale” in our Consolidated Balance Sheets pursuant to entering into an agreement to sell the rig for use in a non-drilling capacity at a price in excess of its carrying value. The sale of the Ocean Tower was completed on October 26, 2009. We recognized a $6.7 million gain on disposition, net of broker commission, which has been reported as “(Gain) on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2009.
17. 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, in accordance with GAAP.
Revenues from contract drilling services by equipment-type are listed below:
Geographic Areas
At December 31, 2009, our drilling rigs were located offshore twelve countries in addition to the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in international operations and our results of operations and the value of our international assets are affected by fluctuations in foreign currency exchange rates. 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, 2009, 2008 and 2007, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.
The following table presents our long-lived tangible assets by geographic location as of December 31, 2009, 2008 and 2007. 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. At December 31, 2009, four of our drilling rigs were in transit (or preparing to mobilize) between geographic locations. These assets have been presented in the tables below within the geographic area in which they are expected to operate.
The following table presents countries where we had a material concentration of operating assets as of December 31, 2009, 2008 and 2007:
As of December 31, 2009, 2008 and 2007, no other countries had more than a 5% concentration of our operating assets.
Major Customers
Our customer base includes major and independent oil and gas companies and government-owned oil companies. No one customer accounted for 10% or more of our total revenues for the year ended December 31, 2007. Revenues from our major customers for the years ended December 31, 2009, 2008 and 2007 that contributed more than 10% of our total revenues are as follows:
Year Ended December 31,
Customer
Petróleo Brasileiro S.A.
15.0 %
13.1 %
9.2 %
18. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 2009 and 2008 is shown below.
(a)
In December 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. See Note 6.
In addition, our results for the fourth quarter of 2009 include a $6.7 million gain on the sale of the Ocean Tower, which was presented as “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2008. See Note 16.
(b)
Results for the fourth quarter of 2009 reflect increased tax expense that arose from (i) a change in mix of domestic and international earnings during the year from that which was previously expected, (ii) impact of foreign exchange differences on foreign tax credits and (iii) an assessment from the Brazilian tax authorities for the years 2004 and 2005. See Note 14.
(c)
Historical data for the four quarterly periods in 2008 have been restated to reflect the effect thereon of the adoption on January 1, 2009 of an accounting standard related to convertible debt. See Note 1.
(d)
In December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance due from one of our customers in the U.K. See Note 6.
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, 2009. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2009.
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, 2009. 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, 2009, our internal control over financial reporting was effective based on those criteria.
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 2009 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 2010 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
Page
(1) Financial Statements
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) Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31, 2009, 2008 and 2007
(3) 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.
Schedule Of Valuation And Qualifying Accounts Disclosure
SCHEDULE II
DIAMOND OFFSHORE DRILLING, INC.
Valuation and Qualifying Accounts
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, 2010.
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*
President, Chief Executive Officer and
February 23, 2010
Lawrence R. Dickerson
Director (Principal Executive Officer)
/s/ GARY T. KRENEK*
Senior Vice President and
February 23, 2010
Gary T. Krenek
Chief Financial Officer
(Principal Financial Officer)
/s/ BETH G. GORDON*
Beth G. Gordon
Controller (Principal Accounting Officer)
February 23, 2010
/s/ JAMES S. TISCH*
James S. Tisch
Chairman of the Board
February 23, 2010
/s/ JOHN R. BOLTON*
John R. Bolton
Director
February 23, 2010
/s/ CHARLES L. FABRIKANT*
Charles L. Fabrikant
Director
February 23, 2010
/s/ PAUL G. GAFFNEY II*
Paul G. Gaffney II
Director
February 23, 2010
/s/ EDWARD GREBOW*
Edward Grebow
Director
February 23, 2010
/s/ HERBERT C. HOFMANN*
Herbert C. Hofmann
Director
February 23, 2010
/s/ ARTHUR L. REBELL*
Arthur L. Rebell
Director
February 23, 2010
/s/ RAYMOND S. TROUBH*
Raymond S. Troubh
Director
February 23, 2010
*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 October 22, 2007) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 26, 2007).
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
Second Supplemental Indenture, dated as of June 6, 2000, 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 4.2 to our Quarterly Report on Form 10-Q/A for the quarterly period ended June 30, 2000) (SEC File No. 1-13926).
4.3
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).
4.4
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).
4.5
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).
4.6
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).
Exhibit No.
Description
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).
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
5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).
10.13+
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).
10.14+
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).
10.15+
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).
10.16+
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).
10.17+
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).
10.18+
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).
10.19*+
Employment Agreement between Diamond Offshore Management Company and Robert G. Blair dated as of December 15, 2006.
Exhibit No.
Description
10.20+
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.