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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 000-53604
NOBLE CORPORATION
(Exact name of registrant as specified in its charter)
| Switzerland | 98-0619597 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. employer identification number) | |
| Dorfstrasse 19A, Baar, Switzerland | 6340 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: 41 (41) 761-65-55
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Shares, Par Value 3.15 CHF per Share | New York Stock Exchange |
Commission file number: 001-31306
NOBLE CORPORATION
(Exact name of registrant as specified in its charter)
| Cayman Islands | 98-0366361 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. employer identification number) |
Suite 3D Landmark Square, 64 Earth Close, P.O. Box 31327
George Town, Grand Cayman, Cayman Islands KY1-1206
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (345) 938-0293
Securities registered pursuant to Sections 12(b) and 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Noble Corporation (Switzerland): Large accelerated filer | x | Accelerated filer | ¨ | Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |||||||
| Noble Corporation (Cayman Islands): Large accelerated filer | ¨ | Accelerated filer | ¨ | Non-accelerated filer | x | Smaller reporting company | ¨ | |||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of June 29, 2012, the aggregate market value of the registered shares of Noble Corporation (Switzerland) held by non-affiliates of the registrant was $8.1 billion based on the closing sale price as reported on the New York Stock Exchange.
Number of shares outstanding and trading at February 11, 2013: Noble Corporation (Switzerland) – 253,225,668
Number of shares outstanding: Noble Corporation (Cayman Islands) – 261,245,693
DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement for the 2013 annual general meeting of the shareholders of Noble Corporation (Switzerland) will be incorporated by reference into Part III of this Form 10-K.
This Form 10-K is a combined annual report being filed separately by two registrants: Noble Corporation, a Swiss corporation (“Noble-Swiss”), and its wholly-owned subsidiary Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Noble-Cayman meets the conditions set forth in General Instructions I (1) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format contemplated by paragraphs (a) and (c) of General Instruction I(2) of Form 10-K.
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This combined Annual Report on Form 10-K is separately filed by Noble Corporation, a Swiss corporation (“Noble-Swiss”), and Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Information in this filing relating to Noble-Cayman is filed by Noble-Swiss and separately by Noble-Cayman on its own behalf. Noble-Cayman makes no representation as to information relating to Noble-Swiss (except as it may relate to Noble-Cayman) or any other affiliate or subsidiary of Noble-Swiss.
This report should be read in its entirety as it pertains to each Registrant. Except where indicated, the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements are combined. References in this Annual Report on Form 10-K to “Noble,” the “Company,” “we,” “us,” “our” and words of similar meaning refer collectively to Noble-Swiss and its consolidated subsidiaries, including Noble-Cayman.
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| Item 1. | Business. |
General
Noble Corporation, a Swiss corporation, is a leading offshore drilling contractor for the oil and gas industry. We perform contract drilling services with our fleet of 79 mobile offshore drilling units located worldwide. We also own one floating production storage and offloading unit. Our fleet consists of 14 semisubmersibles, 14 drillships, 49 jackups and two submersibles, including 11 units under construction as follows:
| • | five dynamically positioned, ultra-deepwater, harsh environment drillships and |
| • | six high-specification, heavy-duty, harsh environment jackups. |
For additional information on the specifications of our fleet, see “Item 2. Properties.—Drilling Fleet.” As of February 7, 2013, approximately 85 percent of our fleet was located outside the United States in the following areas: Mexico, Brazil, the North Sea, the Mediterranean, West Africa, the Middle East, India and Australia. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.
Business Strategy
Our goal is to be the preferred offshore drilling contractor for the oil and gas industry based upon the following overriding principles:
| • | operate in a manner that provides a safe working environment for our employees while protecting the environment and our assets; |
| • | provide an attractive investment vehicle for our shareholders; and |
| • | deliver exceptional customer service through a large, diverse and technically advanced fleet operated by competent personnel. |
We have actively expanded our offshore drilling and deepwater capabilities in recent years through the construction and acquisition of rigs. As part of this technical and operational expansion, we plan to continue pursuing opportunities to upgrade our fleet to achieve greater technological capability, which we believe will lead to increased drilling efficiencies and the ability to complete the increasingly more complex well programs required by our customers.
Our business strategy also focuses on the active expansion of our worldwide deepwater capabilities through upgrades and modifications, acquisitions and divestitures of our standard specification drilling units, as well as the deployment of our drilling assets in important oil and gas producing areas throughout the world.
During 2012, we continued our newbuild program with the following 14 projects:
| • | we commenced operations on three dynamically positioned ultra-deepwater, harsh environment drillships: two Bully-class drillships currently operating in the U.S. Gulf of Mexico and Brazil, respectively, and one Globetrotter-class drillship currently operating in the U.S. Gulf of Mexico; |
| • | we continued construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2013; |
| • | we continued construction on four dynamically positioned, ultra-deepwater, harsh environment drillships at Hyundai Heavy Industries Co. Ltd., the first of which is estimated to be delivered from the shipyard in the second quarter of 2013; and |
| • | we continued construction on six high-specification, heavy duty, harsh environment jackups, the first of which is estimated to be delivered from the shipyard in the second quarter of 2013. |
Capital expenditures, including expenditures related to the items noted above, totaled $1.7 billion during 2012.
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As part of our ongoing strategic planning process, we review our fleet and the strategic benefits of our drilling rigs. As part of this process, we continue to analyze potential divestment of certain of our standard specification units and related assets in one or more transactions. These dispositions may include sales of assets to third parties, a spin-off, or other distribution or separation of assets or a combination of such transactions. In analyzing our disposition alternatives, we consider the strategic benefit to our ongoing operations while seeking to secure what we consider appropriate value for our shareholders. While we may continue to operate some or all standard specification drilling rigs, we have taken certain preliminary steps to put ourselves in a better position to pursue a potential spin-off and/or sale should we decide to do so. These include analyzing the internal restructuring steps necessary for a potential spin-off or sale and related tax considerations, seeking certain preparatory tax rulings and commencing preparation of financial statements for a potential separate group that could be spun off or sold. We have not completed the preliminary work to effect, nor has our board of directors approved, any such transactions. We make no assurance that we will ultimately undertake or consummate any sale, spin-off or separation transactions involving our standard specification assets.
We have entered into an agreement to sell our jackup, the Noble Lewis Dugger, to a third party that owns and operates supply vessels, platform drilling rigs and jackups in Mexico. This unit is being sold for $61 million and the closing is expected to occur in the second quarter of 2013 after the unit has completed its contract with its current customer. The transaction is subject to customary closing conditions. We had entered into an agreement to sell the Noble Don Walker for $18 million. The buyer was unable to close the transaction, although we remain in discussions to potentially extend the sale agreement. The unit has been cold-stacked in Cameroon since 2009.
Demand for our services is a function of the worldwide supply of mobile offshore drilling units. Industry analysts widely acknowledge that a significant expansion of industry supply of both jackups and ultra-deepwater units has commenced, the majority of which currently have no contract. The introduction of non-contracted rigs into the marketplace will increase the supply of rigs which compete for drilling service contracts, which could negatively impact the dayrates we are able to achieve. Our strategy on newbuild construction has generally been to expand our drilling fleet in connection with a long-term drilling contract that covers a substantial portion of our capital investment and provides an acceptable return on our capital employed. However, in response to the addition of a significant number of new, technologically advanced units in the global fleet and changes in customer requirements and preferences, we believe that in order to maintain long-term competitiveness, it has become both necessary and desirable for us to engage in building speculative highly advanced jackups and floating units. Of the units we currently have under construction, two of the ultra-deepwater drillships and two of the heavy-duty, harsh environment jackups are being constructed without customer contracts. We will attempt to secure contracts for these units prior to their completion. We may continue speculative building, even in the absence of contracts for our units already under construction.
From time to time, we evaluate individual rig transactions and business combinations with other parties where we believe we can create shareholder value. We will continue to consider business opportunities that promote our growth strategy and optimize shareholder value.
In previous years, the drilling industry has experienced significant increases in dayrates for drilling services in most markets, coupled with higher demand for drilling equipment and shortages of personnel. This environment drove operating costs higher and magnified the importance of recruiting, training and retaining skilled personnel. While there continues to be instability in the global financial markets we believe the current market offers limited supply and high demand for both our drilling units and the pool of qualified labor to operate our rigs.
In recognition of the importance of our offshore operations personnel in achieving a safety record that has historically outperformed the offshore drilling industry sector and to retain such personnel, we have implemented a number of key operations personnel retention programs. We believe these programs are necessary to complement our other short and long-term incentive programs to attract and retain the skilled personnel we need to maintain safe and efficient operations.
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Drilling Contracts
We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:
| • | contract duration extending over a specific period of time or a period necessary to drill a defined number wells; |
| • | provisions permitting early termination of the contract by the customer (i) if the unit is lost or destroyed or (ii) if operations are suspended for a specified period of time due to breakdown of equipment; |
| • | provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time; |
| • | payment of compensation to us (generally in U.S. Dollars although some customers, typically national oil companies, require a part of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control); |
| • | payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies; and |
| • | provisions that allow us to recover certain cost increases from our customers in certain long-term contracts. |
The terms of some of our drilling contracts permit early termination of the contract by the customer, without cause, generally exercisable upon advance notice to us and in some cases without requiring an early termination payment to us. Our drilling contracts with Petróleos Mexicanos (“Pemex”) in Mexico, for example, allow early cancellation with 30 days or less notice to us without Pemex making an early termination payment.
Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to assume these costs, our operating margins are reduced accordingly. We cannot predict our ability to recover these costs in the future. For shorter moves, such as “field moves,” our customers have generally agreed to assume the costs of moving the unit by paying us a reduced dayrate or “move rate” while the unit is being moved.
For a discussion of our backlog of commitments for contract drilling services, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contract Drilling Services Backlog.”
Acquisition of Frontier Holdings Limited
On July 28, 2010, Noble-Swiss and Noble AM Merger Co., a Cayman Islands company and indirect wholly-owned subsidiary of Noble-Swiss (“Merger Sub”), completed the acquisition of FDR Holdings Limited, a Cayman Islands company (“Frontier”). The Frontier acquisition was for a purchase price of approximately $1.7 billion in cash plus liabilities assumed. The acquisition strategically expanded and enhanced our global fleet. Frontier’s results of operations were included in our results beginning July 28, 2010.
Offshore Drilling Operations
Contract Drilling Services
We conduct offshore contract drilling operations, which accounted for over 97 percent of our operating revenues for the years ended December 31, 2012, 2011 and 2010. We conduct our contract drilling operations principally in the U.S. Gulf of Mexico and Alaska, Mexico, Brazil, the North Sea, the Mediterranean, West Africa, the Middle East, India and Australia. Revenues from Royal Dutch Shell, PLC (“Shell”) and its affiliates accounted for approximately 32 percent, 24 percent and 12 percent of our total operating revenues in 2012, 2011 and 2010, respectively. Revenues from Petróleo Brasileiro S.A. (“Petrobras”) accounted for approximately 14 percent, 18 percent and 19 percent of our total operating revenues in 2012, 2011 and 2010, respectively. Pemex did not account for more than 10 percent of our total operating revenues in 2012. Revenues from Pemex accounted for approximately 15 percent and 20 percent of our total operating revenues in 2011 and 2010, respectively. No other single customer accounted for more than 10 percent of our total operating revenues in 2012, 2011 or 2010.
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Labor Contracts
We perform services for drilling and workover activities covering two platforms off the east coast of Canada; this contract extends through April 2013. We do not own or lease these platforms. Under our labor contracts, we provide the personnel necessary to manage and perform the drilling operations from a drilling platform owned by the operator.
During 2011, we commenced a refurbishment project with our customer, Shell, for one of its rigs. Under the contract, we provided the management and oversight of the project, as well as the personnel necessary to complete the refurbishment. During 2012, the construction phase of the project was completed and the rig began operating off the coast of Alaska. As with the Canadian labor contract noted above, we provide labor personnel and management services on the project but do not own or lease the related rig.
Competition
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and maintenance costs. Some of our competitors may have access to greater financial resources than we do.
In the provision of contract drilling services, competition involves numerous factors, including price, rig availability and suitability, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, industry standing and client relations. We believe that we compete favorably with respect to all of these factors. We follow a policy of keeping our equipment well maintained and technologically competitive. However, our equipment could be made obsolete by the development of new techniques and equipment, regulations or customer preferences.
We compete on a worldwide basis, but competition may vary by region at any particular time. Demand for offshore drilling equipment also depends on the exploration and development programs of oil and gas producers, which in turn are influenced by the financial condition of such producers, by general economic conditions, prices of oil and gas and by political considerations and policies.
In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. We cannot assure that any such shortages experienced in the past will not happen again in the future.
Governmental Regulations and Environmental Matters
Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Our contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, the reduction of greenhouse gas emissions to address climate change, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees and suppliers by foreign contractors. A number of countries actively regulate and control the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to contribute to oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for drilling services, and likely will continue to do so.
The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. Many of the countries in whose waters we operate from time to time regulate the discharge of oil and other contaminants in connection with drilling operations. Failure to comply with these laws and regulations, or failure to obtain or comply with permits, may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. We have made, and will continue to make, expenditures to comply with environmental requirements. To date we have not expended material amounts in order to comply, and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures. Although these requirements impact the energy and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry. However, our business and prospects could be adversely affected by regulatory activity that prohibits or restricts our customers’ exploration and production activities, results in reduced demand for our services or imposes environmental protection requirements that result in increased costs to us, our customers or the oil and natural gas industry in general.
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The following is a summary of some of the existing laws and regulations which apply to our operations in the U.S. Gulf of Mexico to serve as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate.
Spills and Releases. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and similar state laws and regulations, impose joint and several liabilities, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” However, we have to date not received any notification that we are, or may be, potentially responsible for cleanup costs under CERCLA.
Offshore Regulation. The U.S. government has indicated that before any recipient of a deepwater drilling permit may commence drilling, (i) the operator must demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) the chief executive officer of the operator seeking to perform deepwater drilling must certify that the operator has complied with all applicable regulations and (iii) the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) will conduct inspections of such deepwater drilling operation for compliance with the applicable regulations. We cannot predict when the applicable government agency will determine that any deepwater driller is in compliance with the new regulations. Third party challenges to industry operations in the U.S. Gulf of Mexico may also serve to further delay or restrict activities. Further, in 2010 and 2011, the BSEE and its predecessor agency issued initial regulations on the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems (“SEMS”), and mandatory third-party compliance audits. On August 22, 2012, BSEE published a final rule amending the regulations regarding design and operation of well control and other equipment, and a new SEMS rule was sent to the Office of Management and Budget for a 90-day review on January 31, 2013. BSEE has indicated that there will be an additional, separate rulemaking to govern the design, performance and maintenance of blowout preventers but that rule has not yet been published. BSEE has also published a draft statement of policy on safety culture with nine proposed characteristics of a robust safety culture. If the new regulations, policies, operating procedures and possibility of increased legal liability are viewed by our current or future customers as a significant impairment to expected profitability on projects, then they could discontinue or curtail their offshore operations, thereby adversely affecting our operations by limiting drilling opportunities or imposing materially increased costs.
The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and similar regulations impose certain operational requirements on offshore rigs operating in the U.S. Gulf of Mexico and govern liability for leaks, spills and blowouts involving pollutants. The OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.
Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.
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Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and similar state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements as our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by the United States Environmental Protection Agency (“EPA”) or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated under RCRA as hazardous waste. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, a petition is currently before the EPA to revoke the oil and natural gas exploration and production exemption. Any repeal or modification of this or similar exemption in similar state statutes, would increase the volume of hazardous waste we are required to manage and dispose of, and would cause us, as well as our competitors, to incur increased operating expenses with respect to our U.S. operations.
Water Discharges. The U.S. Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and similar state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.
Air Emissions. The U.S. Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Climate Change. There is increasing attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”) emissions. In December 2009, the EPA determined that current and projected concentrations of six key GHG’s in the atmosphere threaten public health and welfare. The EPA subsequently finalized GHG standards for motor vehicles, the effect of which could reduce demand for motor fuels refined from crude oil, and a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, which require the use of “best available control technology” for GHG emissions from new and modified major stationary sources, which can sometimes include drillships. EPA regulations known as the “Tailoring Rule” also require the PSD program to address GHG emissions from relatively smaller stationary sources in the future. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore and offshore oil and natural gas production facilities, on an annual basis. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA.
Further, proposed legislation has been introduced in Congress that would establish an economy-wide cap on emissions of GHG’s in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHG’s. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all countries that had ratified it. Recent international discussions following the United Nations Climate Change Conference in Doha, Qatar in December 2012 are exploring options to replace the Kyoto Protocol. While it is not possible at this time to predict how new treaties and legislation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. Moreover, incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas.
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Safety. The U.S. Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.
Insurance and Indemnification Matters
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires and collisions or groundings of offshore equipment, and damage or loss from adverse weather and sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment.
Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage.
In addition to the contractual indemnities described above, we also carry protection and indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our insurance policy does not exclude losses resulting from our gross negligence or willful misconduct. Our P&I insurance program is renewed in March of each year and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face” included in Item 1A of this Annual Report on Form 10-K.
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report, and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Employees
At December 31, 2012, we had approximately 5,600 employees, excluding approximately 2,000 persons engaged through labor contractors or agencies. Approximately 75 percent of our employees were engaged in operations outside of the U.S. We are not a party to any material collective bargaining agreements, and we consider our employee relations to be satisfactory.
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Financial Information About Segments and Geographic Areas
Information regarding our revenues from external customers, segment profit or loss and total assets attributable to each segment for the last three fiscal years is presented in “Part II Item 8. Financial Statements and Supplementary Data, Note 17 — Segment and Related Information.”
Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is presented in “Part II Item 8. Financial Statements and Supplementary Data, Note 17 — Segment and Related Information.”
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 are available free of charge at our website at http://www.noblecorp.com. These filings are also available to the public at the U.S. Securities and Exchange Commission’s (“SEC”) Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC’s website at http://www.sec.gov.
You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:
| • | Corporate Governance Guidelines; |
| • | Audit Committee Charter; |
| • | Nominating and Corporate Governance Committee Charter; |
| • | Health, Safety, Environment and Engineering Committee Charter; |
| • | Compensation Committee Charter; and |
| • | Code of Business Conduct and Ethics. |
| Item 1A. | Risk Factors. |
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could affect our business, operating results and financial condition, as well as affect an investment in our shares.
Risk Factors Relating to Our Business
Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.
Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration and development and production markets worldwide. Commodity prices, and market expectations of potential changes in these prices, may significantly affect this level of activity. However, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations of future commodity prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:
| • | laws and regulations related to environmental or energy security matters, including those addressing alternative energy sources and the risks of global climate change; |
| • | the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism; |
| • | worldwide demand for oil and gas, which is impacted by changes in the rate of economic growth in the global economy; |
| • | the ability of OPEC to set and maintain production levels and pricing; |
| • | the level of production in non-OPEC countries; |
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| • | the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations; |
| • | the cost of exploring for, developing, producing and delivering oil and gas; |
| • | the discovery rate of new oil and gas reserves; |
| • | the rate of decline of existing and new oil and gas reserves; |
| • | available pipeline and other oil and gas transportation capacity; |
| • | the ability of oil and gas companies to raise capital; |
| • | adverse weather conditions (such as hurricanes and monsoons) and seas; |
| • | the development and exploitation of alternative fuels; |
| • | tax laws, regulations and policies; |
| • | advances in exploration, development and production technology; and |
| • | the availability of, and access to, suitable locations from which our customers can produce hydrocarbons. |
Demand for our drilling services may decrease due to events beyond our control and some of our customers could seek to cancel, terminate or renegotiate their contracts.
Our business could be impacted by events beyond our control including changes in our customers’ drilling programs or budgets or their liquidity (including access to capital), changes in, or prolonged reductions of, prices for oil and gas, or shifts in the relative strength of various geographic drilling markets brought on by economic slowdown, or regional or worldwide recession, any of which could result in deterioration in demand for our drilling services. In addition, our customers may cancel drilling contracts or letter agreements or letters of intent for drilling contracts, or exercise early termination rights found in some of our drilling contracts or available under local law, for a variety of reasons, many of which are beyond our control. Depending upon market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. If the level of demand for our drilling services or conditions in the offshore contract drilling industry declines, our financial position, results of operations and cash flows could be adversely affected.
We may not be able to renew or replace expiring contracts or obtain contracts for our uncontracted newbuilds.
We have a number of customer contracts that will expire in 2013 and 2014. Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions and our customers. Also, of the units we currently have under construction as part of our newbuild program, two of the ultra-deepwater drillships and two of the heavy-duty, harsh environment jackups are being constructed without customer contracts. We will attempt to secure contracts for these units prior to their completion. We may be unable to renew our expiring contracts or obtain new contracts for our newbuilds or the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be below, perhaps substantially below, the existing dayrates, which could have a material adverse effect on our results of operations and cash flows. We may continue speculative building, even in the absence of contracts for our units already under construction.
Our global operations involve additional risks.
We operate in various regions throughout the world that may expose us to political and other uncertainties, including risks of:
| • | terrorist acts, war, revolution and civil disturbances; |
| • | seizure, nationalization or expropriation of property or equipment; |
| • | monetary policies, government debt downgrades and potential defaults, and foreign currency fluctuations and devaluations; |
| • | the inability to repatriate income or capital; |
| • | complications associated with repairing and replacing equipment in remote locations; |
| • | piracy; |
| • | import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control; |
| • | regulatory or financial requirements to comply with foreign bureaucratic actions; and |
| • | changing taxation policies. |
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Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
| • | the importing, exporting, equipping and operation of drilling units; |
| • | repatriation of foreign earnings; |
| • | currency exchange controls; |
| • | oil and gas exploration and development; |
| • | taxation of offshore earnings and earnings of expatriate personnel; and |
| • | use and compensation of local employees and suppliers by foreign contractors. |
Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. For example, as of December 31, 2012, our two rigs operating in Nigeria were operating under temporary import permits and the Department of Petroleum Resources had not yet issued our Nigerian subsidiary a permit to operate as an oil industry service company or licenses to operate the two rigs for the year 2013. It is customary in Nigeria that permits and licenses are issued well into the year to which they pertain and, to date, we have been successful in obtaining new, or extending existing, temporary import permits and other permits and licenses. However, there can be no assurance that we will be able to obtain new permits or further extensions of permits necessary to continue the operation of our rigs in Nigeria. If we cannot obtain a new permit or an extension necessary to continue operations of any rig, we may need to cease operations under the drilling contract for such rig and relocate such rig from Nigerian waters. We cannot predict what impact these events may have on any such contract or our business in Nigeria, and we could face additional fines and sanctions in Nigeria. Furthermore, we cannot predict what changes, if any, relating to temporary import permit policies and procedures may be established or implemented in Nigeria in the future, or how any such changes may impact our business there. For additional information regarding our completed internal investigation of our Nigerian operations and the status of our temporary import permits in Nigeria, see “Part II Item 8. Financial Statements and Supplementary Data, Note 16 — Commitments and Contingencies.” Changes in, compliance with, or our failure to comply with the laws and regulations of the countries where we operate, including Nigeria, may negatively impact our operations in those countries and could have a material adverse effect on our results of operations.
In 2010 the Nigerian Oil and Gas Industry Content Development Bill was signed into law. The law is designed to create Nigerian content in operations and transactions within the Nigerian oil and gas industry. The law sets forth certain requirements for asset ownership and the utilization of Nigerian human resources and goods and services in oil and gas projects and creates a Nigerian Content Development and Monitoring Board to implement and monitor the law and develop regulations pursuant to the law. The Nigerian Content Development and Monitoring Board has indicated that it will require all non-Nigerian offshore drilling companies to reorganize their local operations to include Nigerian indigenous minority interests in the operating assets and to obtain the approval of the Nigerian Content Development and Monitoring Board for future work in Nigeria. The law also establishes a Nigerian Content Development Fund to fund the implementation of the law, and requires that 1 percent of the value of every contract awarded in the Nigerian oil and gas industry be paid into the fund. We continue to closely monitor the implementation of the law and we are in the process of reviewing our structural and strategic alternatives and the associated cost as the law continues to be applied. We cannot predict what impact the law will ultimately have on the drilling industry and our future operations in Nigeria, but the effect on our operations and profitability in the region could be significant.
In addition, other governmental actions, including initiatives by OPEC, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some 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 and our results of operations.
The U.S. government’s regulations and permitting process could have a prolonged and material adverse impact on our U.S. Gulf of Mexico operations.
Subsequent to the April 2010 fire and explosion on the Deepwater Horizon, a competitor’s drilling rig in the U.S. Gulf of Mexico, U.S. governmental authorities implemented a moratorium on and suspension of specified types of drilling activities in the U.S. Gulf of Mexico. In October 2010, the U.S. government lifted the moratorium following adoption of new regulations including a drilling safety rule and a workplace safety rule, each of which imposed multiple obligations relating to offshore drilling operations. These obligations relate to, among other things; additional certifications and verifications relating to compliance with applicable regulations, compatibility of blowout preventers with drilling rigs and well design, third-party inspections and design review of blowout preventers, testing of casing installations, minimum requirements for personnel operating blowout preventers, training in deepwater well control and mandates of maintenance inspections. BSEE’s predecessor agency also proposed to further strengthen these regulations in September 2011. These additional regulations led to additional costs and increased downtime in our U.S. Gulf of Mexico fleet.
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The U.S. government mandated that before beginning a well in the U.S. Gulf of Mexico an operator must: (i) demonstrate that containment resources are available promptly in the event of a deepwater blowout, (ii) have the chief executive officer of the operator seeking to perform deepwater drilling certify that the operator has complied with all applicable regulations and (iii) allow BSEE to conduct inspections of such deepwater drilling operation for compliance with the applicable regulations. Our customers and other operators struggled to implement these new regulations, which resulted in increased downtime and decreased rates for a number of our contracted units when these regulations were instituted. While it appears that operators have become accustomed to these regulations, we cannot predict whether the permitting will continue at the current rate. Increased costs for our customers’ operations and permitting delays could negatively impact their planned or future exploration and development activities, which could result in reduced demand for our services.
Governmental laws and regulations, including environmental laws and regulations, may add to our costs or limit our drilling activity.
Our business is affected by public policy and laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.
The drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and accordingly, we are directly affected by the adoption of laws and regulations that for economic, environmental or other policy reasons curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. 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. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases.
Our operations are also subject to numerous laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. The modification of existing laws or regulations or the adoption of new laws or regulations that result in the curtailment of exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. As a result, the application of these laws could have a material adverse effect on our results of operations by increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons or subjecting us to liability. For example, we, as an operator of mobile offshore drilling units in navigable U.S. waters and certain offshore areas, including the U.S. Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our operations may involve the use or handling of materials that are classified as environmentally hazardous. Laws and regulations protecting the environment have generally become more stringent and in certain circumstances impose “strict liability”, rendering a person liable for environmental damage without regard to negligence or fault. Environmental 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.
In November 2012, the U.S. Coast Guard in Alaska conducted an inspection of our drillship, the Noble Discoverer, and cited a number of deficiencies that needed to be remediated, including issues relating to the main propulsion and safety management system. We began an internal investigation in conjunction with the Coast Guard inspection, and the Coast Guard began their own investigation. We reported certain potential violations of applicable law to the Coast Guard as a result of our internal investigation. These related to what we believe were certain unauthorized disposals of collected deck and sea water from the Noble Discoverer and potential record-keeping issues with the oil record books for the Noble Discoverer and other rigs. The Coast Guard has referred the Noble Discoverer matter to the U.S. Department of Justice (“DOJ”) for further investigation. For additional information regarding these actions relating to the Alaska investigation, see “Part II, Item 8. Financial Statements and Supplementary Data, Note 16— Commitments and Contingencies.”
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Worldwide instability in the financial and credit sectors and economic recession could have a material adverse effect on our financial position, results of operations and cash flows.
Worldwide instability in the financial and credit sectors could reduce the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets could lead to another global economic recession. A slowdown in economic activity caused by a worldwide recession, combined with lower prices for oil and gas, would reduce worldwide demand for energy and demand for drilling services. If demand for drilling services declines again, we could experience a decline in dayrates for new contracts and a slowing in the pace of new contract activity. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices. Demand for our services is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. Any prolonged reduction in oil and natural gas prices or material impairment of our customers’ cash flow or liquidity, including their access to capital, could result in lower levels of exploration, development and production activity. Lower levels of exploration activity could result in a corresponding decline in the demand for our drilling services, which could have a material adverse effect on our financial position, results of operations and cash flows. The financial situation may also adversely affect the ability of shipyards to meet scheduled deliveries of our newbuilds and our ability to renew our fleet through new vessel construction projects and conversion projects.
We are substantially dependent on several of our customers including Shell and Petrobras, and the loss of these customers could have a material adverse effect on our financial condition and results of operations.
We estimate Shell and Petrobras represented approximately 61 percent and 14 percent, respectively, of our backlog at December 31, 2012 and revenues from Shell and Petrobras accounted for approximately 32 percent and 14 percent, respectively, of our total operating revenue for the year ended December 31, 2012. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts in addition to our exposure to credit risk. If either of these customers were to terminate or fail to perform their obligations under their contracts and we were not able to find other customers for the affected drilling units promptly, our financial condition and results of operations could be materially adversely affected.
Construction, conversion or upgrades of rigs are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We currently have multiple new construction and conversion projects underway and we may undertake additional projects in the future. In addition, we make significant upgrade, refurbishment and repair expenditures to our fleet from time to time, particularly as our rigs become older. Some of these expenditures are unplanned. Our customers may also require certain shipyard reliability upgrade projects for our drillships. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
| • | shortages of equipment, materials or skilled labor; |
| • | work stoppages and labor disputes; |
| • | unscheduled delays in the delivery of ordered materials and equipment; |
| • | local customs strikes or related work slowdowns that could delay importation of equipment or materials; |
| • | weather interferences; |
| • | difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions; |
| • | design and engineering problems; |
| • | inadequate regulatory support infrastructure in the local jurisdiction; |
| • | latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions; |
| • | unforeseen increases in the cost of equipment, labor and raw materials, particularly steel; |
| • | unanticipated actual or purported change orders; |
| • | client acceptance delays; |
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| • | disputes with shipyards and suppliers; |
| • | delays in, or inability to obtain, access to funding; |
| • | shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and |
| • | failure or delay of third-party equipment vendors or service providers. |
The failure to complete a rig upgrade or new construction on time, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair may not earn a dayrate during the period they are out of service.
We could be adversely affected by violations of applicable anti-corruption laws and our failure to comply with the terms of our settlement agreements with the DOJ and SEC.
We operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and our code of business conduct and ethics. We are subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”) and similar laws in other countries. Any violation of the FCPA or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
In 2007, we began an internal investigation of the legality under the FCPA of certain activities in Nigeria. In November 2010, we finalized settlements of this matter with each of the SEC and the DOJ. Under the settlements with the DOJ and SEC, we agreed to, among other things, pay certain fines and interest and disgorge certain profits, cooperate with the DOJ, comply with the FCPA, comply with certain self-reporting and annual reporting obligations and comply with an injunction restraining us from violating the anti-bribery, books and records and internal controls provisions of the FCPA. Our ability to comply with the terms of the settlements is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and supervise, train and retain competent employees, and the efforts of our employees to comply with applicable law and our code of business conduct and ethics.
Also, in January 2011, the Nigerian Economic and Financial Crimes Commission and the Nigerian Attorney General Office initiated an investigation into these same activities. A subsidiary of Noble-Swiss resolved this matter through the execution of a non-prosecution agreement dated January 28, 2011. Pursuant to this agreement, the subsidiary paid $2.5 million to resolve all charges and claims of the Nigerian government.
Any additional investigation by these or other agencies could damage our reputation and result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. Further, resolving any additional investigations could be expensive and consume significant time and attention of our senior management. For instance, in February 2012, the SEC charged one current and two former employees of ours with violating the FCPA in connection with the events that were the subject of the internal investigations we began in 2007, as described above. We do not believe that the SEC pleadings against these individuals introduce material facts that were not addressed in our internal investigation, which we resolved with the SEC and the DOJ in November 2010. We are not a party to the SEC proceedings against these individuals, and we do not believe the charges against the individuals will result in fines, sanctions or civil or criminal penalties against us. However, these actions may consume the attention of management and damage our reputation.
Possible changes in tax laws could affect us and our shareholders.
We operate through various subsidiaries in numerous countries throughout the world. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in Switzerland, the U.S. or jurisdictions in which we or any of our subsidiaries operate or are incorporated.
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Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If these laws, treaties or regulations change or other taxing authorities do not agree with our assessment of the effects of such laws, treaties and regulations, this could have a material adverse effect on us, including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.
In addition, the manner in which our shareholders are taxed on distributions on, and dispositions of, our shares could be affected by changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in Switzerland, the U.S. or other jurisdictions in which our shareholders are resident. Any such changes could result in increased taxes for our shareholders and affect the trading price of our shares.
Our business involves numerous operating hazards.
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires and collisions or groundings of offshore equipment, and damage or loss from adverse weather and seas. These hazards could cause personal injury or loss of life, suspend drilling operations or seriously damage or destroy the property and equipment involved, result in claims by employees, customers or third parties and, in addition to causing environmental damage, could cause substantial damage to oil and natural gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services, or personnel shortages. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by oil and gas companies.
The contract drilling industry is a highly competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be reduced.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and maintenance costs. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a job. Mergers among oil and natural gas exploration and production companies from time to time may reduce the number of available clients, resulting in increased price competition.
Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates, followed by periods of lower demand, excess rig supply and low dayrates. Periods of excess rig supply intensify the competition in the industry and may result in some of our rigs being idle for long periods of time. Prolonged periods of low utilization and low dayrates could 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. For example, in 2012 our submersible rig fleet, consisting of two cold stacked rigs, was partially impaired due to the declining market outlook for drilling services for this rig type. We estimated the fair value of the rigs based on the salvage value of the rigs and a recent transaction involving a similar unit owned by a peer company (Level 2 fair value measurement). Based on these estimates, we recognized a charge of approximately $13 million for the year ended December 31, 2012.
The increase in supply created by the number and types of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. In addition, the supply attributable to newbuild rigs, especially those being built on speculation, could cause a reduction in future dayrates. We are experiencing competition from newbuild jackups that are scheduled to enter the market in 2013 and beyond. The entry of these newbuild jackups into the market may result in lower dayrates for jackups than currently expected. Similarly, there are a number of deepwater newbuilds that are scheduled to enter the market over the next several years, which could also adversely affect the dayrates for these units.
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As a result of our significant cash flow needs, we may be required to incur additional indebtedness, or delay or cancel discretionary capital expenditures.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
| • | committed capital expenditures, including expenditures for newbuild projects currently underway; |
| • | normal recurring operating expenses; |
| • | discretionary capital expenditures, including various capital upgrades; |
| • | payments of dividends; and |
| • | repayment of maturing debt. |
In order to fund our capital expenditures, we may need funding beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our existing bank credit facilities and commercial paper program. We may raise such additional capital in a number of ways, including accessing capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on terms acceptable to us or at all.
Our ability to obtain financing or to access the capital markets may be limited by our financial condition at the time of any such financing and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and uncertainties that are beyond our control. Even if we are successful in obtaining additional capital through debt financings, incurring additional indebtedness may significantly increase our interest expense and may reduce our flexibility to respond to changing business and economic conditions or to fund working capital needs, because we will require additional funds to service our outstanding indebtedness.
We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.
We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face.
We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of coverage, the requirements of our customer contracts and applicable legal requirements. We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.
Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, we do not insure against all possible hazards and risks. Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by U.S. laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes.
In addition, the damage sustained to offshore oil and gas assets as a result of hurricanes in recent years has negatively impacted the energy insurance market, resulting in more restrictive and expensive coverage for U.S. named windstorm perils. Accordingly, we have elected to significantly reduce the named windstorm insurance on our rigs operating in the U.S. Gulf of Mexico. Presently, we insure the Noble Jim Thompson, Noble Amos Runner and Noble Driller for “total loss only” when caused by a named windstorm. Our customer assumes the risk of loss on the Noble Bully I due to a named windstorm event up to $450 million per occurrence pursuant to the terms of the drilling contract relating to such vessel, provided that we are responsible for the first $25 million per occurrence for such named windstorm events. The remaining rigs in the U.S. Gulf of Mexico are self-insured for named windstorm perils. Our rigs located in the Mexico portion of the Gulf of Mexico remain covered by commercial insurance for windstorm damage. If one or more future significant weather-related events occur in the Gulf of Mexico, or in any other geographic area in which we operate, we may experience increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.
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Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so.
Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies 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 loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. 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 or cash flows.
Failure to attract and retain highly skilled personnel or an increase in personnel costs could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our drilling units. As the demand for drilling services and the size of the worldwide industry fleet increases, shortages of qualified personnel have occurred from time to time. These shortages could result in our loss of qualified personnel to competitors, impair our ability to attract and retain qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could adversely affect our operations.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not 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 are 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, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, governmental claims for taxes or duties, 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 negative outcomes, costs of attorneys, the allocation of management’s time and attention, and other factors.
Forward-Looking Statements
This report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report regarding the Frontier transaction and integration, contract backlog, fleet status, our financial position, business strategy, timing or results of acquisitions or dispositions, backlog, completion and acceptance of our newbuild rigs, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation or investigation, plans and objectives of management for future operations, foreign currency requirements, results of joint ventures, indemnity and other contract claims, construction of rigs, industry conditions including the effect of disruptions of drilling in the U.S. Gulf of Mexico, access to financing, impact of competition, governmental regulations and permitting, availability of labor, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, and timing for compliance with any new regulations are forward-looking statements. When used in this
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report, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. These factors include those described in “Risk Factors” above, or in our other SEC filings, among others. Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks when you are evaluating us.
| Item 1B. | Unresolved Staff Comments. |
None.
| Item 2. | Properties. |
Drilling Fleet
Our drilling fleet is composed of the following types of units: semisubmersibles, drillships, jackups and submersibles. Each type of drilling rig is described further below. We also own one floating production storage and offloading unit (“FPSO”). Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and the environment of the intended drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.
Semisubmersibles
Semisubmersibles are floating platforms which, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the hull is below the water surface during drilling operations. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system and can drill in many areas where jackups cannot drill. However, semisubmersibles normally require water depth of at least 200 feet in order to conduct operations. Certain of our semisubmersibles are capable of drilling in water depths of up to 12,000 feet.
The semisubmersible fleet consists of 14 units, including:
| • | five Noble EVA-4000™ semisubmersibles; |
| • | three Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles; |
| • | two Pentagone 85 semisubmersibles; |
| • | two Bingo 9000 design unit semisubmersibles; |
| • | one Aker H-3 Twin Hull S1289 Column semisubmersible; and |
| • | one Offshore Co. SCP III Mark 2 semisubmersible. |
Drillships
Our drillships are self-propelled vessels. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system. Our drillships are capable of drilling in water depths from 1,000 to 12,000 feet. The maximum drilling depth of our drillships ranges from 20,000 feet to 40,000 feet.
The drillship fleet consists of 14 units, including:
| • | four dynamically positioned, ultra-deepwater, harsh environment drillships currently under construction, the first of which is estimated to be delivered from the shipyard in the second quarter of 2013; |
| • | three dynamically positioned Gusto Engineering Pelican Class drillships; |
| • | two dynamically positioned Bully-class drillships operated by us through a 50 percent joint venture with a subsidiary of Shell; |
| • | one dynamically positioned Globetrotter-class drillship; |
| • | one dynamically positioned Globetrotter-class drillship currently under construction, which is scheduled to be delivered to our customer in the fourth quarter of 2013; |
| • | one conventionally moored Sonat Discoverer Class drillship capable of drilling in Arctic environments; |
| • | one dynamically positioned NAM Nedlloyd-C drillship; and |
| • | one conventionally moored conversion class drillship. |
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Jackups
We currently have 49 jackups in our fleet, including six high-specification, heavy duty, harsh environment jackups currently under construction. Jackups are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established for support. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. All of our jackups are independent leg (i.e., the legs can be raised or lowered independently of each other) and cantilevered. A cantilevered jackup has a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over pre-existing platforms or structures. Moving a rig to the drill site involves jacking up its legs until the hull is floating on the surface of the water. The hull is then towed to the drill site by tugs and the legs are jacked down to the ocean floor. The jacking operation continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position. Our jackups are capable of drilling to a maximum depth of 30,000 feet in water depths up to 400 feet.
Submersibles
We have two submersibles in the fleet which are currently cold-stacked. Submersibles are mobile drilling platforms that are towed to the drill site and submerged to drilling position by flooding the lower hull until it rests on the sea floor, with the upper deck above the water surface. Our submersibles are capable of drilling to a maximum depth of 25,000 feet in water depths up to 70 feet.
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Drilling Fleet Table
The following table sets forth certain information concerning our offshore fleet at February 7, 2013. The table does not include any units owned by operators for which we had labor contracts. We operate and own all of the units included in the table.
| Water | Drilling | |||||||||||||||
| Depth | Depth | |||||||||||||||
| Year Built | Rating | Capacity | ||||||||||||||
| Name |
Make | or Rebuilt (1) | (feet) | (feet) | Location | Status (2) | ||||||||||
| Semisubmersibles—14 |
||||||||||||||||
| Noble Amos Runner |
Noble EVA-4000™ | 1999 R/2008 M | 8,000 | 32,500 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Clyde Boudreaux |
F&G 9500 Enhanced Pacesetter | 2007 R/M | 10,000 | 35,000 | Australia | Active | ||||||||||
| Noble Danny Adkins |
Bingo 9000—DP | 2009R | 12,000 | 35,000 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Dave Beard |
F&G 9500 Enhanced Pacesetter—DP | 2009 R | 10,000 | 35,000 | Brazil | Active | ||||||||||
| Noble Driller |
Aker H-3 Twin Hull S1289 Column | 2007 R | 5,000 | 30,000 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Homer Ferrington |
F&G 9500 Enhanced Pacesetter | 2004 R | 7,200 | 30,000 | Israel | Active | ||||||||||
| Noble Jim Day |
Bingo 9000—DP | 2010 R | 12,000 | 35,000 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Jim Thompson |
Noble EVA-4000™ | 1999 R/2006 M | 6,000 | 32,500 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Lorris Bouzigard |
Pentagone 85 | 2003 R | 4,000 | 25,000 | U.S. Gulf of Mexico | Stacked | ||||||||||
| Noble Max Smith |
Noble EVA-4000™ | 1999 R | 7,000 | 30,000 | Brazil | Active | ||||||||||
| Noble Paul Romano |
Noble EVA-4000™ | 1998 R/2007 M | 6,000 | 32,500 | Malta | Active | ||||||||||
| Noble Paul Wolff |
Noble EVA-4000™—DP | 2006 R | 9,200 | 30,000 | Brazil | Active | ||||||||||
| Noble Therald Martin |
Pentagone 85 | 2004 R | 4,000 | 25,000 | Brazil | Active | ||||||||||
| Noble Ton van Langeveld (3) |
Offshore Co. SCP III Mark 2 | 2000 R | 1,500 | 25,000 | U.K. | Active | ||||||||||
| Drillships—14 |
||||||||||||||||
| Noble Bob Douglas |
Hyundai Gusto P 10000 | 2013 N | 12,000 | 40,000 | South Korea | Shipyard | ||||||||||
| Noble Bully I (3)(5) |
GustoMSC Bully PRD 12000 | 2011 N | 8,200 | 40,000 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Bully II (3)(5) |
GustoMSC Bully PRD 12000 | 2011 N | 8,200 | 40,000 | Brazil | Active | ||||||||||
| Noble Discoverer (3) |
Sonat Discoverer Class | 2009 R | 1,000 | 20,000 | Alaska | Active | ||||||||||
| Noble Don Taylor |
Hyundai Gusto P 10000 | 2013 N | 12,000 | 40,000 | South Korea | Shipyard | ||||||||||
| Noble Duchess |
Conversion | 2012 R | 1,500 | 25,000 | India | Active | ||||||||||
| Noble Globetrotter I (3) |
Globetrotter Class | 2011 N | 10,000 | 30,000 | U.S. Gulf of Mexico | Active | ||||||||||
| Noble Globetrotter II (3) |
Globetrotter Class | 2013 N | 10,000 | 30,000 | The Netherlands | Shipyard | ||||||||||
| Noble Leo Segerius |
Gusto Engineering Pelican Class | 2012 R | 5,600 | 20,000 | Brazil | Active | ||||||||||
| Noble Muravlenko |
Gusto Engineering Pelican Class | 1997 R | 4,900 | 20,000 | U.S. Gulf of Mexico | Stacked | ||||||||||
| Noble Phoenix |
Gusto Engineering Pelican Class | 2009 R | 5,000 | 25,000 | Brazil | Active | ||||||||||
| Noble Roger Eason |
NAM Nedlloyd—C | 2013 R | 7,200 | 25,000 | Brazil | Active | ||||||||||
| Noble Sam Croft |
Hyundai Gusto P 10000 | 2014 N | 12,000 | 40,000 | South Korea | Shipyard | ||||||||||
| Noble Newbuild Drillship #4 (3) |
Hyundai Gusto P 10000 | 2014 N | 12,000 | 40,000 | South Korea | Shipyard | ||||||||||
| Independent Leg Cantilevered Jackups—49 (Continued to next page) |
||||||||||||||||
| Dhabi II |
Baker Marine BMC 150 | 2006 R | 150 | 20,000 | U.A.E. | Active | ||||||||||
| Noble Al White (3) |
CFEM T-2005-C | 2005 R | 360 | 30,000 | The Netherlands | Active | ||||||||||
| Noble Alan Hay |
Levingston Class 111-C | 2005 R | 300 | 25,000 | U.A.E. | Active | ||||||||||
| Noble Bill Jennings |
MLT Class 84—E.R.C. | 1997 R | 390 | 25,000 | Mexico | Active | ||||||||||
| Noble Byron Welliver (3) |
CFEM T-2005-C | 1982 | 300 | 30,000 | U.K. | Active | ||||||||||
| Noble Carl Norberg |
MLT Class 82-C | 2003 R | 250 | 20,000 | Mexico | Active | ||||||||||
| Noble Charles Copeland |
MLT Class 82-SD-C | 2001 R | 280 | 20,000 | Saudi Arabia | Active | ||||||||||
| Noble Charlie Yester |
MLT Class 116-C | 1980 | 300 | 25,000 | India | Active | ||||||||||
| Noble Chuck Syring |
MLT Class 82-C | 1996 R | 250 | 20,000 | Qatar | Active | ||||||||||
| Noble David Tinsley |
Modec 300C-38 | 2010 R | 300 | 25,000 | U.A.E. | Active | ||||||||||
| Noble Dick Favor |
Baker Marine BMC 150 | 2004 R | 150 | 20,000 | U.A.E. | Active | ||||||||||
| Noble Don Walker |
Baker Marine BMC 150-SD | 1992R | 150 | 20,000 | Cameroon | Stacked | ||||||||||
| Noble Earl Frederickson |
MLT Class 82-SD-C | 1999 R | 250 | 20,000 | Mexico | Active | ||||||||||
| Noble Ed Holt |
Levingston Class 111-C | 2003 R | 300 | 25,000 | India | Active | ||||||||||
| Noble Ed Noble |
MLT Class 82-SD-C | 2003 R | 250 | 20,000 | Nigeria | Active | ||||||||||
| Noble Eddie Paul |
MLT Class 84—E.R.C. | 1995 R | 390 | 25,000 | Mexico | Active | ||||||||||
| Noble Gene House |
Modec 300C-38 | 1998 R | 300 | 25,000 | Saudi Arabia | Active | ||||||||||
| Noble Gene Rosser |
Levingston Class 111-C | 1996 R | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble George McLeod |
F&G L-780 MOD II | 1995 R | 300 | 25,000 | U.A.E. | Active | ||||||||||
| Noble George Sauvageau (3) |
NAM Nedlloyd-C | 1981 | 250 | 25,000 | Denmark | Active | ||||||||||
| Noble Gus Androes |
Levingston Class 111-C | 2004 R | 300 | 30,000 | Qatar | Active | ||||||||||
| Noble Hans Deul (3) |
F&G JU-2000E | 2009 N | 400 | 30,000 | U.K | Active | ||||||||||
See footnotes on the following page.
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| Water | Drilling | |||||||||||||||
| Depth | Depth | |||||||||||||||
| Year Built | Rating | Capacity | ||||||||||||||
| Name |
Make | or Rebuilt (1) | (feet) | (feet) | Location | Status (2) | ||||||||||
| Independent Leg Cantilevered Jackups—49 (Continued from previous page) |
||||||||||||||||
| Noble Harvey Duhaney |
Levingston Class 111-C | 2001 R | 300 | 25,000 | Qatar | Active | ||||||||||
| Noble Houston Colbert (3) |
F&G JU-3000N | 2013 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Noble Jimmy Puckett |
F&G L-780 MOD II | 2002 R | 300 | 25,000 | Qatar | Active | ||||||||||
| Noble Joe Beall |
Modec 300C-38 | 2004 R | 300 | 25,000 | Saudi Arabia | Active | ||||||||||
| Noble John Sandifer |
Levingston Class 111-C | 1995 R | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble Johnnie Hoffman |
Baker Marine BMC 300 | 1993 R | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble Julie Robertson (3) (4) |
BMC 300 Harsh Weather Class | 2001 R | 390 | 25,000 | U.K. | Active | ||||||||||
| Noble Kenneth Delaney |
F&G L-780 MOD II | 1998 R | 300 | 25,000 | India | Active | ||||||||||
| Noble Leonard Jones |
MLT Class 53—E.R.C. | 1998 R | 390 | 25,000 | Mexico | Active | ||||||||||
| Noble Lewis Dugger |
Levingston Class 111-C | 1997 R | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble Lloyd Noble |
MLT Class 82-SD-C | 1990 R | 250 | 20,000 | Cameroon | Active | ||||||||||
| Noble Lynda Bossler (3) |
MSC/CJ-46 | 1982 | 250 | 25,000 | The Netherlands | Active | ||||||||||
| Noble Mick O’Brien (3) |
F&G JU-3000N | 2013 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Noble Percy Johns |
F&G L-780 MOD II | 1995 R | 300 | 25,000 | Nigeria | Active | ||||||||||
| Noble Piet van Ede (3) |
MSC/CJ-46 | 1982 | 250 | 25,000 | The Netherlands | Active | ||||||||||
| Noble Regina Allen (3) |
F&G JU-3000N | 2013 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Noble Roger Lewis |
F&G JU-2000E | 2007 | 400 | 30,000 | Saudi Arabia | Active | ||||||||||
| Noble Ronald Hoope (3) |
MSC/CJ-46 | 1982 | 250 | 25,000 | The Netherlands | Active | ||||||||||
| Noble Roy Butler |
F&G L-780 MOD II | 1998 R | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble Roy Rhodes |
MLT Class 116-C | 2009 R | 300 | 25,000 | Oman | Active | ||||||||||
| Noble Sam Noble |
Levingston Class 111-C | 1982 | 300 | 25,000 | Mexico | Active | ||||||||||
| Noble Sam Turner (3) |
F&G JU-3000N | 2014 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Noble Scott Marks (3) |
F&G JU-2000E | 2009 N | 400 | 30,000 | Saudi Arabia | Active | ||||||||||
| Noble Tom Jobe |
MLT Class 82-SD-C | 1982 | 250 | 25,000 | Mexico | Active | ||||||||||
| Noble Tom Prosser (3) |
F&G JU-3000N | 2014 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Noble Tommy Craighead |
F&G L-780 MOD II | 2003 R | 300 | 25,000 | Gabon | Active | ||||||||||
| Noble Newbuild Jackup #6 (3) |
F&G JU-3000N | 2014 N | 400 | 30,000 | Singapore | Shipyard | ||||||||||
| Submersibles—2 |
||||||||||||||||
| Noble Joe Alford |
Pace Marine 85G | 2006 R | 70 | 25,000 | U.S. Gulf of Mexico | Stacked | ||||||||||
| Noble Lester Pettus |
Pace Marine 85G | 2007 R | 70 | 25,000 | U.S. Gulf of Mexico | Stacked | ||||||||||
| FPSO- 1 |
||||||||||||||||
| Seillean |
Harland & Wolf Shipbuilding | 2008 R | N/A | N/A | U.S. Gulf of Mexico | Stacked | ||||||||||
Footnotes to Drilling Fleet Table
| 1. | Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management. Rigs designated with an “N” are newbuilds. Rigs designated with an “M” have been upgraded to the Noble NC-5SM mooring standard. |
| 2. | Rigs listed as “active” were either operating under contract or were actively seeking contracts; rigs listed as “shipyard” are in a shipyard for construction, repair, refurbishment or upgrade; rigs listed as “stacked” are idle without a contract and are not actively marketed in present market conditions. |
| 3. | Harsh environment capability. |
| 4. | Although designed for a water depth rating of 390 feet of water in a non-harsh environment, the rig is currently equipped with legs adequate to drill in approximately 200 feet of water in a harsh environment. We own the additional leg sections required to extend the drilling depth capability to 390 feet of water. |
| 5. | We own and operate the Noble Bully I and Noble Bully II through joint ventures with a subsidiary of Shell. Under the terms of the joint venture agreements, each party has an equal 50 percent ownership stake in both vessels. |
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Facilities
Our corporate headquarters is located in Baar, Switzerland, and we maintain offices for executive officers and selected personnel in Geneva, Switzerland. We also maintain office space in Sugar Land, Texas, where significant worldwide global support activity occurs. In addition, we own and lease administrative and marketing offices, and sites used primarily for storage, maintenance and repairs, and research and development for drilling rigs and equipment in various locations worldwide.
| Item 3. | Legal Proceedings. |
Information regarding legal proceedings is set forth in Note 16 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.
| Item 4. | Mine Safety Disclosures. |
Not applicable.
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Market for Shares and Related Shareholder Information
Noble-Swiss shares are listed and traded on the New York Stock Exchange under the symbol “NE”. The following table sets forth for the periods indicated the high and low sales prices and dividends or returns of capital declared and paid in U.S. Dollars per share:
| Dividends | ||||||||||||
| Declared and | ||||||||||||
| High | Low | Paid | ||||||||||
| 2012 |
||||||||||||
| Fourth quarter |
$ | 39.81 | $ | 33.51 | $ | 0.13 | ||||||
| Third quarter |
38.60 | 32.21 | 0.13 | |||||||||
| Second quarter |
38.82 | 29.13 | 0.14 | |||||||||
| First quarter |
41.25 | 30.29 | 0.14 | |||||||||
| 2011 |
||||||||||||
| Fourth quarter |
$ | 38.42 | $ | 28.58 | $ | 0.14 | ||||||
| Third quarter |
39.70 | 27.68 | 0.17 | |||||||||
| Second quarter |
46.10 | 37.51 | 0.15 | |||||||||
| First quarter |
46.12 | 35.64 | 0.14 | |||||||||
The declaration and payment of dividends or returns of capital require authorization of the shareholders of Noble-Swiss. The amount of such dividends, distributions and returns of capital will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors and our shareholders.
On February 11, 2013, there were 253,225,668 shares outstanding held by 794 shareholder accounts of record.
Swiss Tax Consequences to Shareholders of Noble-Swiss
The tax consequences discussed below are not a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Noble. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares and the procedures for claiming a refund of withholding tax.
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Swiss Income Tax on Dividends and Similar Distributions
A non-Swiss holder will not be subject to Swiss income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. However, dividends and similar distributions are subject to Swiss withholding tax. See “—Swiss Withholding Tax–Dividends to Shareholders.”
Swiss Wealth Tax
A non-Swiss holder will not be subject to Swiss wealth taxes unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.
Swiss Capital Gains Tax upon Disposal of Shares
A non-Swiss holder will not be subject to Swiss income taxes for capital gains unless the holder’s shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. In such case, the non-Swiss holder is required to recognize capital gains or losses on the sale of such shares, which will be subject to cantonal, communal and federal income tax.
Swiss Withholding Tax—Dividends to Shareholders
A Swiss withholding tax of 35 percent is due on dividends to our shareholders from us, regardless of the place of residency of the shareholder (subject to the exceptions discussed under “—Exemption from Swiss Withholding Tax–Distributions to Shareholders” below). We will be required to withhold at such rate and remit on a net basis any payments made to a holder of our shares and pay such withheld amounts to the Swiss federal tax authorities. Please see “—Refund of Swiss Withholding Tax on Dividends and Other Distributions.”
Exemption from Swiss Withholding Tax—Distributions to Shareholders
Under present Swiss tax law, distributions to shareholders in relation to a reduction of par value are exempt from Swiss withholding tax. Since January 1, 2011, distributions to shareholders out of qualifying additional paid-in capital for Swiss statutory purposes are exempt from the Swiss withholding tax. Consequently, we expect that a substantial amount of any potential future distributions, whether distributed as a reduction of par value or directly out of qualifying additional paid-in capital may be exempt from Swiss withholding tax.
Repurchases of Shares
Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to the 35 percent Swiss withholding tax. However, for shares repurchased for capital reduction, the portion of the repurchase price attributable to the par value of the shares repurchased will not be subject to the Swiss withholding tax. Since January 1, 2011, the portion of the repurchase price attributable to the qualifying additional paid-in capital for Swiss statutory reporting purposes of the shares repurchased will also not be subject to the Swiss withholding tax. We would be required to withhold at such rate the tax from the difference between the repurchase price and the related amount of par value and the related amount of qualifying additional paid-in capital. We would be required to remit on a net basis the purchase price with the Swiss withholding tax deducted to a holder of our shares and pay the withholding tax to the Swiss federal tax authorities.
With respect to the refund of Swiss withholding tax from the repurchase of shares, see “—Refund of Swiss Withholding Tax on Dividends and Other Distributions.”
In most instances, Swiss companies listed on the SIX Swiss Exchange (“SIX”), carry out share repurchase programs through a “second trading line” on the SIX. Swiss institutional investors typically purchase shares from shareholders on the open market and then sell the shares on the second trading line back to the company. The Swiss institutional investors are generally able to receive a full refund of the withholding tax. Due to, among other things, the time delay between the sale to the company and the institutional investors’ receipt of the refund, the price companies pay to repurchase their shares has historically been slightly higher (but less than 1 percent) than the price of such companies’ shares in ordinary trading on the SIX first trading line.
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We do not expect to be able to use the SIX second trading line process to repurchase our shares because we do not currently intend to list our shares on the SIX. However, we have in the past and intend to continue to follow an alternative process whereby we expect to be able to repurchase our shares in a manner that should allow Swiss institutional market participants selling the shares to us to receive a refund of the Swiss withholding tax and, therefore, accomplish the same purpose as share repurchases on the second trading line at substantially the same cost to us and such market participants as share repurchases on a second trading line.
The repurchase of shares for purposes other than capital reduction, such as to retain as treasury shares for use in connection with stock incentive plans, convertible debt or other instruments within certain periods, will generally not be subject to Swiss withholding tax.
Refund of Swiss Withholding Tax on Dividends and Other Distributions
Swiss holders – A Swiss tax resident, corporate or individual, can recover the withholding tax in full if such resident is the beneficial owner of our shares at the time the dividend or other distribution becomes due and provided that such resident reports the gross distribution received on such resident’s income tax return, or in the case of an entity, includes the taxable income in such resident’s income statement.
Non-Swiss holders – If the shareholder that receives a distribution from us is not a Swiss tax resident, does not hold our shares in connection with a permanent establishment or a fixed place of business maintained in Switzerland, and resides in a country that has concluded a treaty for the avoidance of double taxation with Switzerland for which the conditions for the application and protection of and by the treaty are met, then the shareholder may be entitled to a full or partial refund of the withholding tax described above. The procedures for claiming treaty refunds (and the time frame required for obtaining a refund) may differ from country to country.
Switzerland has entered into bilateral treaties for the avoidance of double taxation with respect to income taxes with numerous countries, including the U.S., whereby under certain circumstances all or part of the withholding tax may be refunded.
U.S. residents – The Swiss-U.S. tax treaty provides that U.S. residents eligible for benefits under the treaty can seek a refund of the Swiss withholding tax on dividends for the portion exceeding 15 percent (leading to a refund of 20 percent) or a full refund in the case of qualified pension funds.
As a general rule, the refund will be granted under the treaty if the U.S. resident can show evidence of:
| • | beneficial ownership, |
| • | U.S. residency, and |
| • | meeting the U.S.-Swiss tax treaty’s limitation on benefits requirements. |
The claim for refund must be filed with the Swiss federal tax authorities (Eigerstrasse 65, 3003 Berne, Switzerland), no later than December 31 of the third year following the year in which the dividend payments became due. The relevant Swiss tax form is Form 82C for companies, 82E for other entities and 82I for individuals. These forms can be obtained from any Swiss Consulate General in the U.S. or from the Swiss federal tax authorities at the address mentioned above or at www.estv.admin.ch. Each form needs to be filled out in triplicate, with each copy duly completed and signed before a notary public in the U.S. Evidence that the withholding tax was withheld at the source must also be included.
Stamp duties in relation to the transfer of shares – The purchase or sale of our shares may be subject to Swiss federal stamp taxes on the transfer of securities irrespective of the place of residency of the purchaser or seller if the transaction takes place through or with a Swiss bank or other Swiss securities dealer, as those terms are defined in the Swiss Federal Stamp Tax Act and no exemption applies in the specific case. If a purchase or sale is not entered into through or with a Swiss bank or other Swiss securities dealer, then no stamp tax will be due. The applicable stamp tax rate is 0.075 percent for each of the two parties to a transaction and is calculated based on the purchase price or sale proceeds. If the transaction does not involve cash consideration, the transfer stamp duty is computed on the basis of the market value of the consideration.
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Purchases of Shares
The following table sets forth for the periods indicated certain information with respect to repurchases by Noble-Swiss of its shares:
|
Period |
Total Number of Shares Purchased (2) |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (1) |
||||||||||||
| October 2012 |
189 | $ | 38.09 | — | 6,769,891 | |||||||||||
| November 2012 |
— | $ | 0.00 | — | 6,769,891 | |||||||||||
| December 2012 |
2,200 | $ | 34.28 | — | 6,769,891 | |||||||||||
| (1) | All share purchases made in the open market and were pursuant to the share repurchase program which our Board of Directors authorized and adopted and our shareholders approved. Our repurchase program has no date of expiration. |
| (2) | Amounts represent shares surrendered by employees for withholding taxes payable upon the vesting of restricted stock or exercise of stock options. |
Stock Performance Graph
This graph shows the cumulative total shareholder return of our shares over the five-year period from January 1, 2008 to December 31, 2012. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our shares and the two indices on January 1, 2008 and that all dividends or distributions and returns of capital were reinvested on the date of payment.
| INDEXED RETURNS | ||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| Company Name / Index |
2008 | 2009 | 2010 | 2011 | 2012 | |||||||||||||||
| Noble Corporation |
$ | 39.76 | $ | 73.66 | $ | 66.55 | $ | 57.12 | $ | 66.82 | ||||||||||
| S&P 500 Index |
63.00 | 79.67 | 91.68 | 93.61 | 108.59 | |||||||||||||||
| Dow Jones U.S. Oil Equipment & Services |
40.70 | 67.22 | 85.60 | 74.96 | 75.20 | |||||||||||||||
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Investors are cautioned against drawing any conclusions from the data contained in the graph, as past results are not necessarily indicative of future performance.
The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.
| Item 6. | Selected Financial Data. |
The following table sets forth selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2012, which information is derived from our audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Item 8 of this Annual Report on Form 10-K.
| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||
| Statement of Income Data |
||||||||||||||||||||
| Operating revenues |
$ | 3,547,012 | $ | 2,695,832 | $ | 2,807,176 | $ | 3,640,784 | $ | 3,446,501 | ||||||||||
| Net income attributable to Noble Corporation |
522,344 | 370,898 | 773,429 | 1,678,642 | 1,560,995 | |||||||||||||||
| Net income per share: |
||||||||||||||||||||
| Basic |
2.05 | 1.46 | 3.03 | 6.44 | 5.85 | |||||||||||||||
| Diluted |
2.05 | 1.46 | 3.02 | 6.42 | 5.81 | |||||||||||||||
| Balance Sheet Data (at end of period) |
||||||||||||||||||||
| Cash and marketable securities |
$ | 282,092 | $ | 239,196 | $ | 337,871 | $ | 735,493 | $ | 513,311 | ||||||||||
| Property and equipment, net |
13,025,972 | 12,130,345 | 10,213,158 | 6,815,637 | 5,647,017 | |||||||||||||||
| Total assets |
14,607,774 | 13,495,159 | 11,302,387 | 8,396,896 | 7,106,799 | |||||||||||||||
| Long-term debt |
4,634,375 | 4,071,964 | 2,686,484 | 750,946 | 750,789 | |||||||||||||||
| Total debt (1) |
4,634,375 | 4,071,964 | 2,766,697 | 750,946 | 923,487 | |||||||||||||||
| Total equity |
8,488,290 | 8,097,852 | 7,287,634 | 6,788,432 | 5,290,715 | |||||||||||||||
| Other Data |
||||||||||||||||||||
| Net cash from operating activities |
$ | 1,381,693 | $ | 740,240 | $ | 1,636,902 | $ | 2,131,267 | $ | 1,888,192 | ||||||||||
| Net cash from investing activities |
(1,790,888 | ) | (2,521,546 | ) | (2,896,469 | ) | (1,489,610 | ) | (1,129,293 | ) | ||||||||||
| Net cash from financing activities |
452,091 | 1,682,631 | 861,945 | (419,475 | ) | (406,646 | ) | |||||||||||||
| Capital expenditures |
1,669,811 | 2,621,235 | 1,406,010 | 1,426,049 | 1,231,321 | |||||||||||||||
| Working capital |
393,876 | 232,432 | 110,347 | 1,049,243 | 561,348 | |||||||||||||||
| Cash dividends/par value reduction declared per share (2) (3) |
0.54 | 0.60 | 0.88 | 0.18 | 0.91 | |||||||||||||||
| (1) | Consists of Long-Term Debt and Current Maturities of Long-Term Debt. |
| (2) | From the third quarter of 2009 through the second quarter of 2012, we paid a return on capital in the form of par value reductions, in lieu of dividends, based upon an amount in Swiss Francs. In the third and fourth quarters of 2012, we paid a dividend from the capital contribution reserve. Amounts listed are in U.S. Dollars at the exchange rate that the dividend was paid. |
| (3) | The par value reductions or cash dividends declared in 2010 and 2008 includes a special dividend of approximately $0.56 and $0.75 per share, respectively. |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
The following discussion is intended to assist you in understanding our financial position at December 31, 2012 and 2011, and our results of operations for each of the years in the three-year period ended December 31, 2012. You should read the accompanying consolidated financial statements and related notes in conjunction with this discussion.
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Executive Overview
Our 2012 financial and operating results include:
| • | operating revenues totaling $3.5 billion; |
| • | net income of $522 million or $2.05 per diluted share; |
| • | net cash from operating activities totaling $1.4 billion; and |
| • | an increase in debt to 35.3 percent of total capitalization at the end of 2012, up from 33.5 percent at the end of 2011 due to the issuance of $1.2 billion in senior notes partially offset by a $635 million decrease in the amount of debt being drawn on our credit facilities and commercial paper program. |
During 2012, we continued to see modest improvement in the offshore drilling market even as the underlying commodity markets were subject to short-term volatility. In the U.S. Gulf of Mexico, the granting of permits and publication of new safety rules during the latter half of 2011, has led to increased activity levels within the industry. The activity reflects the positive long-term outlook for commodity prices, which has led to increased activity by our customers and contributed to improved dayrates for deepwater and ultra-deepwater rigs worldwide, and excellent geologic success, which is leading to a backlog of appraisal and development projects.
There continues to be doubt regarding the sustainability of the global economic recovery, which is proceeding unevenly in different geographic regions. There is also hesitation regarding recovery in the credit markets, particularly in Europe, which some analysts predict could be the catalyst for a worldwide recession. Finally, political instability, especially in the Middle East and North Africa, has further created uncertainty within the marketplace. These factors may continue to impact the price of oil and gas commodities for the foreseeable future, and in turn, could impact the offshore drilling market.
Despite the instability in the global economy and commodity prices noted above, the market for offshore drilling services has continued the upward trend that began during the second half of 2011. We believe both the short-term and long-term outlook for the deep and ultra-deepwater markets continues to strengthen. Market dayrates for new ultra-deepwater units consistently remained above $500,000 throughout the year, which is higher than rates seen in recent years. A number of fixtures have exceeded $550,000, and in certain cases even exceeded $600,000. Our market analysis indicates that there is little, if any, availability of ultra-deepwater units for 2013. In addition, availability of ultra-deepwater units in 2014 continues to decrease. Utilization rates for jackups stabilized in 2011, and improved in most regions during 2012. We have seen tangible market activity and anticipate a favorable environment for these rigs in the short-term. We continue to see differentiation in the jackup market, with newer units having utilization rates and dayrates exceeding those for units that entered service before 2000. We continue to see improvement in the older jack-up market with increased utilization and competitive dayrates for these rigs as well, with most regions experiencing market utilization of 90 percent or higher.
As part of our strategic planning process, we review our fleet and the strategic benefits of our drilling rigs. As part of this process, we continuously analyze the potential divestment of certain of our standard specification units and related assets in one or more transactions. These dispositions may include sales of assets to third parties, a spin-off or other distribution or separation of assets or a combination of such transactions. In analyzing our disposition alternatives, we consider the strategic benefit to our ongoing operations while seeking to secure what we consider appropriate value for our shareholders. While we could continue to operate some or all standard specification drilling rigs, we have taken certain preliminary steps to put ourselves in a better position to pursue a potential spin-off and/or sale should we decide to do so. These include analyzing the internal restructuring steps necessary for a potential spin-off or sale and related tax considerations, seeking certain preparatory tax rulings and commencing preparation of financial statements for a potential separate group that could be spun off or sold. We have not completed the preliminary work to effect, nor has our board approved, any such transactions. We make no assurance that we will ultimately undertake any sales or spin-off or separation transactions involving standard specification assets.
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We have actively expanded our offshore drilling and deepwater capabilities in recent years through the construction and acquisition of new rigs. As part of this technical and operational enhancement, we plan to continue pursuing opportunities to upgrade our fleet to achieve greater technological capability, which should increase our operational efficiencies.
During 2012, we continued our newbuild program as indicated by the following activities:
| • | we commenced operations on three dynamically positioned ultra-deepwater, harsh environment drillships: two Bully-class drillships currently operating in the U.S. Gulf of Mexico and Brazil, respectively, and one Globetrotter-class drillship currently operating in the U.S. Gulf of Mexico; |
| • | we continued construction on one dynamically positioned, ultra-deepwater, harsh environment Globetrotter-class drillship, which is scheduled to be delivered to our customer in the fourth quarter of 2013; |
| • | we continued construction on four dynamically positioned, ultra-deepwater, harsh environment drillships at Hyundai Heavy Industries Co. Ltd., the first of which is estimated to be delivered from the shipyard in the second quarter of 2013; and |
| • | we continued construction on six high-specification, heavy duty, harsh environment jackups, the first of which is estimated to be delivered from the shipyard in the second quarter of 2013. |
While we cannot predict the future level of demand or dayrates for our drilling services or future conditions in the offshore contract drilling industry, we continue to believe we are well positioned within the industry and believe our continued newbuild activity will further strengthen our position, especially in deepwater drilling.
We have entered into an agreement to sell our jackup, the Noble Lewis Dugger, to a third party that owns and operates supply vessels, platform drilling rigs and jackups in Mexico. This unit is being sold for $61 million and the closing is expected to occur in the second quarter of 2013 after the unit has completed its contract with its current customer. The transaction is subject to customary closing conditions. We had entered into an agreement to sell the Noble Don Walker for $18 million. The buyer was unable to close the transaction, although we remain in discussions to potentially extend the sale agreement. The unit has been cold-stacked in Cameroon since 2009.
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Contract Drilling Services Backlog
We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth as of December 31, 2012 the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
| Year Ending December 31, | ||||||||||||||||||||||||
| Total | 2013 | 2014 | 2015 | 2016 | 2017-2023 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Contract Drilling Services Backlog |
||||||||||||||||||||||||
| Semisubmersibles/Drillships (1) (5) |
$ | 11,903 | $ | 2,648 | $ | 2,622 | $ | 1,880 | $ | 1,334 | $ | 3,419 | ||||||||||||
| Jackups (2) |
2,443 | 1,372 | 827 | 237 | 7 | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total (3) |
$ | 14,346 | $ | 4,020 | $ | 3,449 | $ | 2,117 | $ | 1,341 | $ | 3,419 | ||||||||||||
|
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|
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|
|
|
|
|||||||||||||
| Percent of Available Days Committed (4) |
74 | % | 50 | % | 22 | % | 10 | % | 5 | % | ||||||||||||||
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|
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|
|
|||||||||||||||
| (1) | Our drilling contracts with Petrobras provide an opportunity for us to earn performance bonuses based on downtime experienced for our rigs operating offshore Brazil. With respect to our semisubmersibles operating offshore Brazil for Petrobras, we have included in our backlog an amount equal to 75 percent of potential performance bonuses for such semisubmersibles. With respect to our drillships presently operating offshore Brazil for Petrobras, we have included in our backlog an amount equal to 75 percent of potential performance bonuses for periods after the estimated completion of certain upgrade projects that are designed to enhance the reliability and operational performance of the drillships. Our backlog for semisubmersibles/drillships includes approximately $197 million attributable to these performance bonuses. |
| The drilling contracts with Shell for the Noble Globetrotter I, Noble Globetrotter II, Noble Jim Thompson, Noble Clyde Boudreaux, Noble Max Smith, Noble Don Taylor and the Noble Jim Day, provide opportunities for us to earn performance bonuses based on key performance indicators as defined by Royal Dutch Shell, PLC (“Shell”). With respect to these contracts, we have included in our backlog an amount equal to 50 percent of the potential performance bonuses for these rigs. Our backlog for these rigs includes approximately $409 million attributable to these performance bonuses. |
| (2) | Pemex has the ability to cancel its drilling contracts on 30 days or less notice without Pemex’s making an early termination payment. At December 31, 2012, we had 12 rigs contracted to Pemex in Mexico, and our backlog includes approximately $613 million related to such contracts. |
| (3) | Our drilling contracts generally provide the customer an early termination right in the event we fail to meet certain performance standards, including downtime thresholds. For example, Petrobras has the right to terminate its contracts in the event of excessive downtime. While we have exceeded downtime thresholds in the past on certain rigs contracted with Petrobras, we have not received any notification concerning contract cancellations nor do we anticipate receiving any such notifications. |
| (4) | Percentages take into account additional capacity from the estimated dates of deployment of our newbuild rigs that are scheduled to commence operations during 2013 through 2015. |
| (5) | Noble and a subsidiary of Shell are involved in joint ventures that own and operate both the Noble Bully I and the Noble Bully II. Under the terms of the joint venture agreements, each party has an equal 50 percent share in both vessels. As of December 31, 2012, the combined amount of backlog for these rigs totals $2.28 billion, all of which is included in our backlog. Noble’s proportional interest in the backlog for these rigs was $1.14 billion. |
Our contract drilling services backlog reported above reflects estimated future revenues attributable to both signed drilling contracts and letters of intent that we expect to realize. A letter of intent is generally subject to customary conditions, including the execution of a definitive drilling contract. It is possible that some customers that have entered into letters of intent will not enter into signed drilling contracts. We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.
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The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods set forth in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, achievement of bonuses, weather conditions and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated.
Nigerian Operations
As previously disclosed, in November 2010 we finalized settlements with the SEC and the DOJ as the result of an internal investigation of the legality under the United States Foreign Corrupt Practices Act (“FCPA”) and local laws of certain reimbursement payments made by our Nigerian affiliate to our customs agents in Nigeria. In January 2011, a subsidiary of Noble-Swiss resolved an investigation by the Nigerian Economic and Financial Crimes Commission and the Nigerian Attorney General Office into these same activities. Any additional investigation by these or other agencies could damage our reputation and result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. Further, resolving any additional investigations could be expensive and consume significant time and attention of our senior management.
Acquisition of Frontier Holdings Limited
On July 28, 2010, Noble-Swiss and Noble AM Merger Co., a Cayman Islands company and indirect wholly-owned subsidiary of Noble-Swiss (“Merger Sub”), completed the acquisition of FDR Holdings Limited, a Cayman Islands company (“Frontier”). Under the terms of the Agreement and Plan of Merger with Frontier and certain of Frontier’s shareholders, Merger Sub merged with and into Frontier, with Frontier surviving as an indirect wholly-owned subsidiary of Noble-Swiss and a wholly-owned subsidiary of Noble-Cayman. The Frontier acquisition was for a purchase price of approximately $1.7 billion in cash plus liabilities assumed and strategically expanded and enhanced our global fleet. Frontier’s results of operations were included in our results beginning July 28, 2010. We funded the cash consideration paid at closing of approximately $1.7 billion using proceeds from our July 2010 offering of senior notes and existing cash on hand.
RESULTS OF OPERATIONS
2012 Compared to 2011
General
The consolidated financial statements of Noble-Swiss include the accounts of Noble-Cayman, and Noble-Swiss conducts substantially all of its business through Noble-Cayman and its subsidiaries. As a result, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between 2012 and 2011, would be the same as the information presented below regarding Noble-Swiss in all material respects, except operating income for Noble-Cayman for the year ended December 31, 2012 was $58 million higher than operating income for Noble-Swiss for the same period, primarily as a result of costs directly attributable to Noble-Swiss for operations support and stewardship related services.
Net income attributable to Noble Corporation for 2012 was $522 million, or $2.05 per diluted share, on operating revenues of $3.5 billion, compared to net income for 2011 of $371 million, or $1.46 per diluted share, on operating revenues of $2.7 billion.
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Rig Utilization, Operating Days and Average Dayrates
Operating revenues and operating costs and expenses for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2012 and 2011 (dollars in thousands):
| Average Rig | Operating | Average | ||||||||||||||||||||||||||||||
| Utilization (1) | Days (2) | Dayrates | ||||||||||||||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | % Change | 2012 | 2011 | % Change | |||||||||||||||||||||||||
| Jackups |
82 | % | 75 | % | 12,966 | 11,794 | 10 | % | $ | 96,696 | $ | 85,510 | 13 | % | ||||||||||||||||||
| Semisubmersibles |
86 | % | 82 | % | 4,382 | 4,176 | 5 | % | 349,205 | 296,331 | 18 | % | ||||||||||||||||||||
| Drillships |
69 | % | 59 | % | 2,023 | 1,284 | 58 | % | 279,432 | 242,019 | 15 | % | ||||||||||||||||||||
| Other |
0 | % | 0 | % | — | — | — | — | — | — | ||||||||||||||||||||||
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| Total |
78 | % | 72 | % | 19,371 | 17,254 | 12 | % | $ | 172,904 | $ | 148,185 | 17 | % | ||||||||||||||||||
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| (1) | Information reflects our policy of reporting on the basis of the number of actively marketed rigs in our fleet excluding newbuild rigs under construction. |
| (2) | Information reflects the number of days that our rigs were operating under contract. |
Contract Drilling Services
The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2012 and 2011 (dollars in thousands):
| Change | ||||||||||||||||
| 2012 | 2011 | $ | % | |||||||||||||
| Operating revenues: |
||||||||||||||||
| Contract drilling services |
$ | 3,349,362 | $ | 2,556,758 | $ | 792,604 | 31 | % | ||||||||
| Reimbursables (1) |
112,956 | 77,278 | 35,678 | 46 | % | |||||||||||
| Other |
265 | 875 | (610 | ) | -70 | % | ||||||||||
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|
|||||||||
| $ | 3,462,583 | $ | 2,634,911 | $ | 827,672 | 31 | % | |||||||||
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| Operating costs and expenses: |
||||||||||||||||
| Contract drilling services |
$ | 1,776,481 | $ | 1,384,200 | $ | 392,281 | 28 | % | ||||||||
| Reimbursables (1) |
91,646 | 56,589 | 35,057 | 62 | % | |||||||||||
| Depreciation and amortization |
745,027 | 647,142 | 97,885 | 15 | % | |||||||||||
| Selling, general and administrative |
97,967 | 90,262 | 7,705 | 9 | % | |||||||||||
| Loss on impairment |
12,710 | — | 12,710 | ** | ||||||||||||
| Gain on contract settlements/extinguishments, net |
(33,255 | ) | (21,202 | ) | (12,053 | ) | 57 | % | ||||||||
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| 2,690,576 | 2,156,991 | 533,585 | 25 | % | ||||||||||||
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| Operating income |
$ | 772,007 | $ | 477,920 | $ | 294,087 | 62 | % | ||||||||
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| (1) | We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. |
| ** | Not a meaningful percentage. |
Operating Revenues. Changes in contract drilling services revenues for the current year as compared to the prior year were driven by increases in both average dayrates and operating days. The 17 percent increase in average dayrates increased revenues by approximately $479 million while the 12 percent increase in operating days increased revenues by an additional $314 million.
The increase in contract drilling services revenues relates to our semisubmersibles, drillships and jackups, which generated approximately $293 million, $255 million and $245 million more revenue, respectively, in 2012.
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The 18 percent increase in semisubmersible average dayrates resulted in a $232 million increase in revenues from the prior year while the increase in operating days of 5 percent resulted in an additional $61 million increase in revenues. The increase in semisubmersibles revenue is a result of our rigs returning to standard operating dayrates after experiencing lower standby rates due to drilling restrictions in the U.S. Gulf of Mexico in the prior year, as well as the Noble Paul Romano returning to work after being stacked for most of the prior year. The increase in operating days is primarily from the Noble Jim Day, the Noble Homer Ferrington, the Noble Paul Romano, the Noble Clyde Boudreaux and the Noble Amos Runner, which all operated during the current year after being off contract for the majority of the prior year.
The increase in drillship revenues was driven by a 58 percent increase in operating days and a 15 percent increase in average dayrates, resulting in a $179 million and a $76 million increase in revenues, respectively, from the prior year. The increase in both average dayrates and operating days was the result of the Noble Bully I, Noble Bully II and Noble Globetrotter I, which commenced their contracts with Shell in March 2012, April 2012 and July 2012, respectively. These increases were partially offset by the Noble Phoenix, which completed its shipyard project and was substituted for the Noble Muravlenko in Brazil during the current year, and a reduced rate on the Noble Roger Eason while it is in the shipyard to undergo its reliability upgrade project.
The 13 percent increase in jackup average dayrates resulted in a $145 million increase in revenues, which was coupled with a 10 percent increase in jackup operating days, resulting in a $100 million increase in revenues from the prior year. The increase in average dayrates resulted from improved market conditions in the global shallow water market throughout the jackup fleet. The increase in utilization primarily related to rigs in Mexico, West Africa and the Middle East, which experienced less downtime during the current year.
Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $392 million for the current year as compared to the prior year. A portion of the increase is due to the crew-up and operating expenses for the recently completed rigs noted above, which have added approximately $139 million in expense in the current year. Excluding the additional expenses related to these rigs, our contract drilling costs increased $253 million in the current year from the prior year. This change was primarily driven by a $75 million increase in labor due to rigs returning, or preparing to return, to work and salary increases effective in the second and third quarters of the prior year, a $47 million increase in shorebase support due to salary increases in the current year and increased project-related costs, a $44 million increase in maintenance and rig-related expense, a $26 million increase in mobilization due to the amortization of certain rig moves and the demobilization of rigs primarily in Mexico, a $20 million increase in insurance costs related to increased premiums on our policy renewed in March 2012, a $14 million increase in rig catering and communications, a $13 million increase in safety, training and regulatory inspections, a $6 million increase in agency and other miscellaneous expenses, a $5 million increase in fuel and transportation costs and a $3 million increase in rotation costs.
Depreciation and amortization increased $98 million in 2012 over 2011, which is primarily attributable to assets placed in service during the current year, including the Noble Bully I, Noble Bully II and the Noble Globetrotter I.
Loss on impairment during the current year related to an impairment charge on our submersible fleet, primarily as a result of the declining market outlook for drilling services for this rig type.
Gain on contract settlements/extinguishments during the current year related to a $28 million gain on the settlement of an action with certain vendors for damages sustained during Hurricane Ike. Additionally, we received $5 million from a claims settlement on the Noble David Tinsley, which had experienced a “punch-through” while being positioned on location in 2009.
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Other
The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2012 and 2011 (dollars in thousands):
| Change | ||||||||||||||||
| 2012 | 2011 | $ | % | |||||||||||||
| Operating revenues: |
||||||||||||||||
| Labor contract drilling services |
$ | 81,890 | $ | 59,004 | $ | 22,886 | 39 | % | ||||||||
| Reimbursables (1) |
2,539 | 1,917 | 622 | 32 | % | |||||||||||
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| $ | 84,429 | $ | 60,921 | $ | 23,508 | 39 | % | |||||||||
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| Operating costs and expenses: |
||||||||||||||||
| Labor contract drilling services |
$ | 46,895 | $ | 33,885 | $ | 13,010 | 38 | % | ||||||||
| Reimbursables (1) |
2,450 | 1,850 | 600 | 32 | % | |||||||||||
| Depreciation and amortization |
13,594 | 11,498 | 2,096 | 18 | % | |||||||||||
| Selling, general and administrative |
2,023 | 1,115 | 908 | 81 | % | |||||||||||
| Loss on impairment |
7,674 | — | 7,674 | ** | ||||||||||||
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| 72,636 | 48,348 | 24,288 | 50 | % | ||||||||||||
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| Operating income |
$ | 11,793 | $ | 12,573 | $ | (780 | ) | -6 | % | |||||||
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| (1) | We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. |
| ** | Not a meaningful percentage. |
Operating Revenues and Costs and Expenses. The increase in both revenue and expense primarily relates to a project with our customer, Shell, for one of its rigs operating under a labor contract in Alaska.
Loss on impairment during the current year related to an impairment charge on certain corporate assets, as a result of a declining market for, and the potential disposal of, the assets.
Other Income and Expenses
Selling, general and administrative expenses. Overall selling, general and administrative expenses increased $9 million in 2012 from 2011 primarily as a result of increased legal and tax expenses related to ongoing projects of $5 million, coupled with increases in employee-related costs of $4 million.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $30 million in 2012 from 2011. The increase is a result of the $1.2 billion of senior notes issued in February 2012, coupled with lower capitalized interest due primarily to the completion of construction on three of our newbuild drillships. During the current year, we capitalized approximately 61 percent of total interest charges versus approximately 69 percent during the prior year.
Income Tax Provision. Our income tax provision increased $74 million in 2012 compared to 2011 primarily as a result of a higher pre-tax earnings and effective tax rate during the current year. Pre-tax earnings increased approximately 61 percent in 2012 compared to 2011 resulting in a $45 million increase in income tax expense. The higher effective tax rate, which was 20.9 percent in 2012 compared to 16.7 percent in 2011, increased income tax expense by approximately $29 million. The increase in the effective tax rate was a result of a change in our geographic mix of our revenues and the resolution of certain discrete tax items.
2011 Compared to 2010
General
The consolidated financial statements of Noble-Swiss include the accounts of Noble-Cayman, and Noble-Swiss conducts substantially all of its business through Noble-Cayman and its subsidiaries. As a result, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between 2011 and 2010, would be the same as the information presented below regarding Noble-Swiss in all material respects, except operating income for Noble-Cayman for the year ended December 31, 2011 was $49 million higher than operating income for Noble-Swiss for the same period, primarily as a result of costs directly attributable to Noble-Swiss for operations support and stewardship related services.
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Net income attributable to Noble Corporation for 2011 was $371 million, or $1.46 per diluted share, on operating revenues of $2.7 billion, compared to net income for 2010 of $773 million, or $3.02 per diluted share, on operating revenues of $2.8 billion.
Rig Utilization, Operating Days and Average Dayrates
Operating revenues and operating costs and expenses for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2011 and 2010 (dollars in thousands):
| Average Rig | Operating | Average | ||||||||||||||||||||||||||||||
| Utilization (1) | Days (2) | Dayrates | ||||||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | % Change | 2011 | 2010 | % Change | |||||||||||||||||||||||||
| Jackups |
75 | % | 79 | % | 11,794 | 12,376 | -5 | % | $ | 85,510 | $ | 96,935 | -12 | % | ||||||||||||||||||
| Semisubmersibles |
82 | % | 86 | % | 4,176 | 3,837 | 9 | % | 296,331 | 288,163 | 3 | % | ||||||||||||||||||||
| Drillships |
59 | % | 89 | % | 1,284 | 1,392 | -8 | % | 242,019 | 256,067 | -5 | % | ||||||||||||||||||||
| Other |
0 | % | 11 | % | — | 95 | -100 | % | — | 355,986 | -100 | % | ||||||||||||||||||||
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| Total |
72 | % | 78 | % | 17,254 | 17,700 | -3 | % | $ | 148,185 | $ | 152,292 | -3 | % | ||||||||||||||||||
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| (1) | Information reflects our policy of reporting on the basis of the number of actively marketed rigs in our fleet excluding newbuild rigs under construction. |
| (2) | Information reflects the number of days that our rigs were operating under contract. |
Contract Drilling Services
The following table sets forth the operating revenues and the operating costs and expenses for our contract drilling services segment for 2011 and 2010 (dollars in thousands):
| Change | ||||||||||||||||
| 2011 | 2010 | $ % |
|
|||||||||||||
| Operating revenues: |
||||||||||||||||
| Contract drilling services |
$ | 2,556,758 | $ | 2,695,493 | $ | (138,735 | ) | -5 | % | |||||||
| Reimbursables (1) |
77,278 | 73,959 | 3,319 | 4 | % | |||||||||||
| Other |
875 | 2,332 | (1,457 | ) | -62 | % | ||||||||||
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| $ | 2,634,911 | $ | 2,771,784 | $ | (136,873 | ) | -5 | % | ||||||||
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| Operating costs and expenses: |
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| Contract drilling services |
$ | 1,384,200 | $ | 1,177,800 | $ | 206,400 | 18 | % | ||||||||
| Reimbursables (1) |
56,589 | 56,674 | (85 | ) | 0 | % | ||||||||||
| Depreciation and amortization |
647,142 | 528,011 | 119,131 | 23 | % | |||||||||||
| Selling, general and administrative |
90,262 | 91,094 | (832 | ) | -1 | % | ||||||||||
| Gain on contract extinguishments, net |
(21,202 | ) | — | (21,202 | ) | ** | ||||||||||
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| 2,156,991 | 1,853,579 | 303,412 | 16 | % | ||||||||||||
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| Operating income |
$ | 477,920 | $ | 918,205 | $ | (440,285 | ) | -48 | % | |||||||
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| (1) | We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. |
| ** | Not a meaningful percentage. |
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Operating Revenues. Decreased contract drilling services revenues for the current year as compared to the prior year was driven by reductions in both average dayrates and operating days. The 3 percent decrease in average dayrates reduced revenues by approximately $71 million, and the 3 percent decrease in operating days decreased revenues by an additional $68 million.
The decrease in contract drilling services revenues primarily relates to our jackups, drillships and FPSO, which generated approximately $191 million, $46 million and $34 million less revenue, respectively, in 2011.
The decrease in jackup average dayrates of 12 percent resulted in a $135 million decrease in revenues from the prior year. The reduction in average dayrates was primarily from the contractual repricing of rigs in the Middle East, the North Sea, and Mexico for changes in market conditions in the global shallow water market. The 5 percent decline in jackup operating days resulted in a $56 million decline in revenues. The decrease in utilization primarily related to rigs coming off contract in Mexico and the Middle East during 2011, the majority of which did not return to work until the latter part of the year.
The decrease in drillship revenue was primarily driven by reduced dayrates of 5 percent and an 8 percent decrease in operating days, which resulted in decreased revenues of $18 million and $28 million, respectively, from the prior year. The decrease in drillship revenue is primarily the result of increased downtime in Brazil, as rigs entered the shipyard for upgrades and repairs.
Revenue from the Noble Seillean decreased $34 million as it was not under contract in 2011.
The decreases in revenue for the above rig classes were partially offset by an increase in revenue of $132 million from our semisubmersibles. The increase was primarily attributable to a 9 percent increase in operating days and 3 percent increase in average dayrates, which contributed additional revenue in 2011 of $98 million and $34 million, respectively. The increase is primarily attributable to operations from the newbuilds, Noble Dave Beard and Noble Jim Day, which were added to the fleet in March 2010 and January 2011, respectively. Additionally, the Noble Driller was added to the fleet in July 2010 as part of the Frontier acquisition.
Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $206 million for the current year as compared to the prior year. The rigs added to the fleet as part of the Frontier acquisition and the Noble Dave Beard and the Noble Jim Day added approximately $120 million of operating costs in the current year. Excluding the additional expenses related to these rigs, our contract drilling costs increased $86 million in the current year from the prior year. This increase was primarily driven by a $22 million increase in maintenance and rig-related expenses, $20 million increase in mobilization costs, $18 million increase in labor costs, and an $11 million increase in safety and training costs. These cost increases were primarily for our rigs returning, or preparing to return, to work in Brazil and Mexico. Additionally, rotation costs and operations support costs increased $10 million and $5 million, respectively.
Depreciation and amortization increased $119 million in 2011 over 2010 as a result of depreciation on newbuilds placed into service, rigs added to the fleet as part of the Frontier acquisition and additional depreciation related to other capital expenditures on our fleet since the beginning of 2010.
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Other
The following table sets forth the operating revenues and the operating costs and expenses for our other services for 2011 and 2010 (dollars in thousands):
| Change | ||||||||||||||||
| 2011 | 2010 | $ | % | |||||||||||||
| Operating revenues: |
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| Labor contract drilling services |
$ | 59,004 | $ | 32,520 | $ | 26,484 | 81 | % | ||||||||
| Reimbursables (1) |
1,917 | 2,872 | (955 | ) | -33 | % | ||||||||||
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| $ | 60,921 | $ | 35,392 | $ | 25,529 | 72 | % | |||||||||
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| Operating costs and expenses: |
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| Labor contract drilling services |
$ | 33,885 | $ | 22,056 | $ | 11,829 | 54 | % | ||||||||
| Reimbursables (1) |
1,850 | 2,740 | (890 | ) | -32 | % | ||||||||||
| Depreciation and amortization |
11,498 | 11,818 | (320 | ) | -3 | % | ||||||||||
| Selling, general and administrative |
1,115 | 903 | 212 | 23 | % | |||||||||||
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| 48,348 | 37,517 | 10,831 | 29 | % | ||||||||||||
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| Operating income |
$ | 12,573 | $ | (2,125 | ) | $ | 14,698 | -692 | % | |||||||
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| (1) | We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. |
Operating Revenues and Costs and Expenses. The increase in both revenue and expense primarily relates to the commencement of a refurbishment project with our customer, Shell, for one of its rigs to be operated under a labor contract in Alaska, combined with operational increases and foreign currency fluctuations in our Canadian operations.
Other Income and Expenses
Selling, general and administrative expenses. Overall selling, general and administrative expenses were consistent with 2010 as a $6 million increase primarily related to ongoing legal and tax expenses in the current year was offset by a $6 million decrease resulting from the absence of costs related to our completed FCPA investigation in the prior year.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $46 million in 2011 from 2010. The increase is a result of $1.25 billion of debt issued in July 2010, which was used to partially fund the Frontier acquisition, $1.1 billion of debt issued in February 2011, which was primarily used to repay the outstanding balance on our revolving credit facility and to repay our portion of outstanding debt under the joint venture credit facilities, and current year drawdowns on the credit facilities.
Income Tax Provision. Our income tax provision decreased $70 million in 2011 compared to 2010 primarily due to a reduction in pre-tax earnings, which was partially offset by a higher effective tax rate. Pre-tax earnings decreased approximately 52 percent in 2011 compared to 2010 resulting in a reduction of approximately $75 million in income tax expense. The higher effective tax rate, which was 16.7 percent in 2011 compared to 15.6 percent in 2010, increased income tax expense by approximately $5 million. The increase in the effective tax rate was a result of a change in our geographic revenue mix primarily resulting from drilling restrictions in the U.S. Gulf of Mexico, partially offset by the resolution of discrete tax items.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Net cash from operating activities in 2012 was $1.4 billion, which compared to $740 million and $1.6 billion in 2011 and 2010, respectively. The increase in net cash from operating activities in 2012 compared to 2011 was primarily attributable to a significant increase in net income coupled with favorable changes in deferred taxes and other current liabilities, partially offset by an increase in accounts receivable. We had working capital of $394 million and $232 million at December 31, 2012 and 2011, respectively. Our total debt as a percentage of total debt plus equity increased to 35.3 percent at December 31, 2012 from 33.5 percent at December 31, 2011, primarily as a result of our $1.2 billion senior notes offering in February 2012, partially offset by a net reduction in indebtedness outstanding on our credit facilities and commercial paper program during the year.
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Our principal sources of capital in 2012 were the $1.4 billion in cash generated from operating activities noted above and our $1.2 billion senior notes offering in February 2012. Cash generated during the current year was primarily used to fund our capital expenditure program and to repay borrowings outstanding under our credit facilities and commercial paper program.
Our currently anticipated cash flow needs, both in the short-term and long-term, include the following:
| • | committed capital expenditures, including expenditures for newbuild projects currently underway; |
| • | normal recurring operating expenses; |
| • | discretionary capital expenditures, including various capital upgrades; |
| • | payments of dividends; and |
| • | repayment of maturing debt. |
We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our existing credit facilities and commercial paper program and issuances of unsecured long-term debt. However, to adequately cover our expected cash flow needs, we may require capital in excess of the amount provided through these sources, and we may delay or cancel certain discretionary capital expenditures as necessary.
At December 31, 2012, we had a total contract drilling services backlog of approximately $14.3 billion. Our backlog as of December 31, 2012 reflects a commitment of 74 percent of available days for 2013. See “Contract Drilling Services Backlog” for additional information regarding our backlog.
Capital Expenditures
Our primary use of available liquidity during 2013 will be for capital expenditures. Capital expenditures, including capitalized interest, totaled $1.7 billion, $2.6 billion and $1.4 billion for 2012, 2011 and 2010, respectively. Capital expenditures for 2010 do not include the fair value of assets acquired as part of the Frontier acquisition.
At December 31, 2012, we had 11 rigs under construction, and capital expenditures, excluding capitalized interest, for new construction during 2012 totaled $587 million, as follows (in millions):
| Rig type/name |
||||
| Currently under construction |
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| Drillships |
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| Noble Globetrotter II |
$ | 203.8 | ||
| Noble Don Taylor (formerly HHI Drillship I) |
86.7 | |||
| Noble Bob Douglas (formerly HHI Drillship II) |
62.3 | |||
| Noble Sam Croft (formerly HHI Drillship III) |
4.8 | |||
| HHI Drillship IV |
3.3 | |||
| Jackups |
||||
| Noble Sam Turner (formerly Noble Jackup IV) |
47.5 | |||
| Noble Tom Prosser (formerly Noble Jackup V) |
46.2 | |||
| Noble Jackup VI |
46.2 | |||
| Noble Regina Allen (formerly Noble Jackup I) |
11.9 | |||
| Noble Houston Colbert (formerly Noble Jackup III) |
5.9 | |||
| Noble Mick O’Brien (formerly Noble Jackup II) |
5.4 | |||
| Recently completed construction projects |
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| Noble Globetrotter I |
44.1 | |||
| Noble Bully II |
17.0 | |||
| Noble Bully I |
1.6 | |||
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| Total Newbuild Capital Expenditures |
$ | 586.7 | ||
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In addition to the newbuild expenditures noted above, capital expenditures during 2012 consisted of the following:
| • | $693 million for major projects, including subsea-related expenditures; |
| • | $254 million for other capitalized expenditures, including upgrades and replacements to drilling equipment that generally have a useful life ranging from 3 to 5 years; and |
| • | $136 million in capitalized interest. |
Our total capital expenditures budget for 2013 is approximately $2.7 billion, which is currently anticipated to be spent as follows:
| • | approximately $1.5 billion in newbuild expenditures; |
| • | approximately $870 million in major projects, including subsea-related expenditures; and |
| • | approximately $320 million in sustaining capitalized expenditures. |
In addition to the amounts noted above, we anticipate incurring additional capitalized interest, which may fluctuate as a result of the timing of completion of ongoing projects. In connection with our capital expenditure program, we have entered into certain commitments, including shipyard and purchase commitments, for approximately $2.8 billion at December 31, 2012, of which we expect to spend approximately $1.7 billion in 2013.
From time to time we consider possible projects that would require capital expenditures or other cash expenditures that are not included in our capital budget, and such unbudgeted capital or cash expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Other factors that could cause actual capital expenditures to materially exceed planned capital expenditures include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements and changes in design criteria or specifications during repair or construction.
Distributions of Capital and Dividends
Our most recent quarterly dividend payment to shareholders, which was declared on February 1, 2013 and paid on February 21, 2013 to holders of record on February 11, 2013, was $0.13 per share, or an aggregate of approximately $33 million. The declaration and payment of dividends, or returns of capital in the form of par value reductions, require authorization of the shareholders of Noble-Swiss. The amount of such dividends, distributions and returns of capital will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors and shareholders.
Recently, our Board of Directors approved as a proposal to shareholders at our upcoming annual general meeting scheduled for April 26, 2013 the payment of a dividend funded from our capital contribution reserve in a total amount equal to $1.00 per share to be paid in four equal installments scheduled for August 2013, November 2013, February 2014 and May 2014.
Credit Facilities and Senior Unsecured Notes
Credit Facilities and Commercial Paper Program
Noble currently has a maximum available capacity of $800 million on our credit facility maturing in 2015 and $1.5 billion on our credit facility maturing in 2017 (together referred to as the “Credit Facilities”). Our total debt related to the Credit Facilities and commercial paper program was $340 million at December 31, 2012 as compared to $975 million at December 31, 2011. During 2012, we undertook a series of transactions that increased our liquidity. We see this as a necessary step to finance our future capital commitments. The following summarizes the recent activity regarding our Credit Facilities and commercial paper program:
| • | in June 2012, we replaced our $575 million credit facility scheduled to mature in 2013, with a new $1.2 billion credit facility, which matures in 2017; |
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| • | in September 2012, we established a commercial paper program, which will allow us to issue up to $1.8 billion in unsecured commercial paper notes. Amounts issued under the commercial paper program are supported by the unused committed capacity under our Credit Facilities and, as such, are classified as long-term on our Consolidated Balance Sheet; and |
| • | in January 2013, we increased the maximum amount available under our Credit Facilities from $1.8 billion to $2.3 billion. The maximum amount available under our credit facility maturing in 2015 was increased from $600 million to $800 million and the maximum amount available under our credit facility maturing in 2017 was increased from $1.2 billion to $1.5 billion. |
The Credit Facilities provide us with the ability to issue up to $375 million in letters of credit in the aggregate. The issuance of letters of credit does not increase our borrowings outstanding under the Credit Facilities, but it does reduce the amount available. At December 31, 2012, we had no letters of credit issued under the Credit Facilities.
Senior Unsecured Notes
Our total debt related to senior unsecured notes was $4.3 billion at December 31, 2012 as compared to $3.1 billion at December 31, 2011. The increase in debt is a result of the issuance of $1.2 billion aggregate principal amount of senior notes in February 2012, which we issued through our indirect wholly-owned subsidiary, Noble Holding International Limited (“NHIL”). These senior notes were issued in three separate tranches, with $300 million of 2.50% Senior Notes due 2017, $400 million of 3.95% Senior Notes due 2022, and $500 million of 5.25% Senior Notes due 2042. The weighted average coupon of all three tranches is 4.13%. The net proceeds of approximately $1.19 billion, after expenses, were primarily used to repay the then outstanding balance on our Credit Facilities.
Our 5.875% Senior Notes mature during the second quarter of 2013. We anticipate using availability under our Credit Facilities or commercial paper program to repay the outstanding balance; therefore, we continue to report the balance as long-term at December 31, 2012.
Covenants
The Credit Facilities and commercial paper program are guaranteed by our indirect wholly-owned subsidiaries, NHIL and Noble Drilling Corporation (“NDC”). The covenants and events of default under the Credit Facilities are substantially similar, and each facility contains a covenant that limits our ratio of debt to total tangible capitalization, as defined in the Credit Facilities, to 0.60. At December 31, 2012, our ratio of debt to total tangible capitalization was less than 0.36. We were in compliance with all covenants under the Credit Facilities as of December 31, 2012.
In addition to the covenants from the Credit Facilities noted above, the indentures governing our outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. In addition, there are restrictions on incurring or assuming certain liens and sale and lease-back transactions. At December 31, 2012, we were in compliance with all our debt covenants. We continually monitor compliance with the covenants under our notes and, based on our expectations for 2013, expect to remain in compliance during the year.
Other
At December 31, 2012, we had letters of credit of $48 million and performance and tax assessment bonds totaling $264 million supported by surety bonds outstanding. Additionally, certain of our subsidiaries issue guarantees to the temporary import status of rigs or equipment imported into certain countries in which we operate. These guarantees are issued in-lieu of payment of custom, value added or similar taxes in those countries.
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Summary of Contractual Cash Obligations and Commitments
The following table summarizes our contractual cash obligations and commitments at December 31, 2012 (in thousands):
| Payments Due by Period | ||||||||||||||||||||||||||||||||
| Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Other | |||||||||||||||||||||||||
| Contractual Cash Obligations |
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| Long-term debt obligations (1) |
$ | 4,634,375 | $ | 639,794 | $ | 249,799 | $ | 350,000 | $ | 299,952 | $ | 299,852 | $ | 2,794,978 | $ | — | ||||||||||||||||
| Interest payments |
2,949,927 | 205,343 | 186,353 | 177,902 | 161,252 | 153,240 | 2,065,837 | — | ||||||||||||||||||||||||
| Operating leases |
79,808 | 28,182 | 22,756 | 10,420 | 4,062 | 3,567 | 10,821 | — | ||||||||||||||||||||||||
| Pension plan contributions |
136,220 | 8,166 | 7,388 | 8,123 | 10,200 | 10,232 | 92,111 | — | ||||||||||||||||||||||||
| Purchase commitments (2) |
2,758,833 | 1,730,862 | 1,027,971 | — | — | — | — | — | ||||||||||||||||||||||||
| Dividends |
66,369 | 66,369 | — | — | — | — | — | — | ||||||||||||||||||||||||
| Tax reserves (3) |
124,972 | — | — | — | — | — | — | 124,972 | ||||||||||||||||||||||||
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| Total contractual cash obligations |
$ | 10,750,504 | $ | 2,678,716 | $ | 1,494,267 | $ | 546,445 | $ | 475,466 | $ | 466,891 | $ | 4,963,747 | $ | 124,972 | ||||||||||||||||
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| (1) | In 2013, our 5.875% senior notes and amounts outstanding under our commercial paper program mature. We anticipate using availability on our Credit Facilities or commercial paper program to repay these outstanding balances; therefore, we have shown the entire $300 million senior notes balance and $340 million commercial paper program balance as long-term on our December 31, 2012 Consolidated Balance Sheet. |
| (2) | Purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases. |
| (3) | Tax reserves are included in “Other” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See Note 12 to our accompanying consolidated financial statements. |
At December 31, 2012, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit and surety bond obligations are not normally called, as we typically comply with the underlying performance requirement.
The following table summarizes our other commercial commitments at December 31, 2012 (in thousands):
| Amount of Commitment Expiration Per Period | ||||||||||||||||||||||||||||
| Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | ||||||||||||||||||||||
| Contractual Cash Obligations |
||||||||||||||||||||||||||||
| Letters of Credit |
$ | 47,652 | $ | 47,514 | $ | — | $ | 138 | $ | — | $ | — | $ | — | ||||||||||||||
| Surety bonds |
263,978 | 177,832 | 4,199 | 43,795 | 21,945 | 16,207 | — | |||||||||||||||||||||
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| Total commercial commitments |
$ | 311,630 | $ | 225,346 | $ | 4,199 | $ | 43,933 | $ | 21,945 | $ | 16,207 | $ | — | ||||||||||||||
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Critical accounting policies and estimates that most significantly impact our consolidated financial statements are described below.
Principles of Consolidation
The consolidated financial statements include our accounts, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. Our consolidated financial statements include the accounts of two joint ventures, in each of which we own a 50 percent interest. Our ownership interest meets the definition of variable interest under Financial Accounting Standards Board (“FASB”) codification and we have determined that we are the primary beneficiary. Intercompany balances and transactions have been eliminated in consolidation.
The combined joint venture carrying amount of the Bully-class drillships at December 31, 2012 totaled $1.4 billion, which was primarily funded through partner equity contributions. During 2012, these rigs commenced the operating phases of their contracts. Current year revenues and net income related to these joint ventures totaled $237 million and $71 million, respectively.
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Table of Contents
Property and Equipment
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. At December 31, 2012 and 2011, we had $2.7 billion and $4.4 billion of construction-in-progress, respectively. Such amounts are included in “Drilling equipment and facilities” in the accompanying Consolidated Balance Sheets. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to twenty-five years.
Interest is capitalized on construction-in-progress at the interest rate on debt incurred for construction or at the weighted average cost of debt outstanding during the period of construction. Capitalized interest for the years ended December 31, 2012, 2011 and 2010 was $136 million, $122 million and $83 million, respectively.
Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Drilling equipment and facilities” in the Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $303 million and $233 million at December 31, 2012 and 2011, respectively. Depreciation expense related to overhauls and asset replacement totaled $113 million, $103 million and $102 million for the years ended December 31, 2012, 2011 and 2010, respectively.
We evaluate the realization of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our assets. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet or exceed our estimated assumptions, for a given rig class, we may take an impairment loss in the future.
During the current year we determined that our submersible rig fleet, consisting of two cold stacked rigs, was partially impaired due to the declining market outlook for drilling services for this rig type. We estimated the fair value of the rigs based on the salvage value of the rigs and a recent transaction involving a similar unit owned by a peer company (Level 2 fair value measurement). Based on these estimates, we recognized a charge of approximately $13 million for the year ended December 31, 2012. Also, during the current year, we determined that certain corporate assets were partially impaired due to a declining market for, and the potential disposal of, the assets. We estimated the fair value of the asset based on a signed letter of intent to sell the asset (Level 2 fair value measurement). Based on these estimates, we recognized a charge of approximately $7 million for the year ended December 31, 2012.
Insurance Reserves
We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability, and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.
Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. At December 31, 2012 and 2011, loss reserves for personal injury and protection claims totaled $20 million and $21 million, respectively, and such amounts are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
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Revenue Recognition
Revenues generated from our dayrate-basis drilling contracts and labor contracts are recognized as services are performed. Revenues from bonuses are recognized when earned.
We may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a drilling unit from one market to another are recognized over the term of the related drilling contract. Absent a contract, the initial mobilization costs of newbuild rigs from the shipyard are deferred and amortized over the life of the rig. Subsequent costs incurred to relocate drilling units to more promising geographic areas in which a contract has not been secured are expensed as incurred. Lump-sum payments received from customers relating to specific contracts, including equipment modifications, are deferred and amortized to income over the term of the drilling contract. Upon completion of our drilling contracts, any demobilization revenues received are recognized as income, as are any related expenses.
Deferred revenues under drilling contracts totaled $252 million and $139 million at December 31, 2012 and 2011, respectively. Such amounts are included in either “Other Current Liabilities” or “Other Liabilities” in our Consolidated Balance Sheets, based upon our expected time of recognition.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
Income Taxes
We operate through various subsidiaries in numerous countries throughout the world including the United States. Income taxes have been provided based on the laws and rates in effect in the countries in which operations are conducted or in which we or our subsidiaries are considered resident for income tax purposes. The income and withholding tax rates and methods of computing taxable income vary significantly for each jurisdiction. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the U.S., Switzerland or jurisdictions in which we or any of our subsidiaries operate or are resident. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If the U.S. Internal Revenue Service (“IRS”) or other taxing authorities do not agree with our assessment of the effects of such laws, treaties and regulations, this could have a material adverse effect on us, including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions. Our income tax expense is expected to fluctuate from year to year as our operations and income fluctuates in the different taxing jurisdictions.
We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. The IRS has completed its examination of our tax reporting for the taxable year ended December 31, 2008. The examination team has proposed adjustments with respect to certain items that were reported by us for the 2008 tax year. We believe that we have accurately reported all amounts included in our 2008 tax returns, and have filed protests with the IRS Appeals Office contesting the examination team’s proposed adjustments, and we are still waiting on a final resolution of these issues. We intend to vigorously defend our reported positions. The IRS has begun its examination of our tax reporting for the taxable year ended December 31, 2009. We believe that we have accurately reported all amounts in our 2009 tax returns. During the third quarter of 2012, a U.S. subsidiary of Frontier concluded its audit with the IRS for its 2007 and 2008 tax returns, resulting in no change to income tax expense. Furthermore, we are currently contesting several non-U.S. tax assessments and may contest future assessments when we disagree with those assessments based on the technical merits of the positions established at the time of the filing of the tax return. We believe the ultimate resolution of the outstanding assessments, for which we have not made any accrual, will not have a material adverse effect on our consolidated financial statements. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of the existing or future assessments.
Our Mexican income tax returns have been examined for the 2002 through 2007 periods and audit claims have been assessed for approximately $321 million (including interest and penalties). During 2011, we received from the Regional Chamber of the Federal Tax Court adverse decisions with respect to approximately $6 million in assessments related to depreciation deductions, which we are appealing. We are also contesting all other assessments in Mexico. Tax authorities in Mexico and other jurisdictions may issue additional assessments or pursue legal actions as a result of tax audits and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions.
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Additional audit claims of approximately $123 million attributable to income, customs and other business taxes have been assessed against us in other jurisdictions. We have contested, or intend to contest, these assessments, including through litigation if necessary, and we believe the ultimate resolution, for which we have not made any accrual, will not have a material adverse effect on our consolidated financial statements.
Applicable income and withholding taxes have not been provided on undistributed earnings of our subsidiaries. We do not intend to repatriate such undistributed earnings except for distributions upon which incremental income and withholding taxes would not be material.
In certain jurisdictions we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred assets. Any change in the ability to utilize such deferred assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.
In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. In addition, we are involved in several litigation matters, some of which could lead to potential liability to us. We follow FASB standards regarding contingent liabilities which are discussed in “Part II Item 8. Financial Statements and Supplementary Data, Note 16- Commitments and Contingencies” of our annual report on form 10-K.
New Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, which amends FASB Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures.” This amended guidance clarifies the wording used to describe many of the requirements in accounting literature for measuring fair value and for disclosing information about fair value measurements. The goal of the amendment is to create consistency between the United States and international accounting standards. The guidance is effective for annual and interim reporting periods beginning on or after December 15, 2011. Our adoption of this guidance did not have a material impact on our financial condition, results of operations, cash flows or financial disclosures.
In June 2011, the FASB issued ASU No. 2011-05, which amends ASC Topic 220, “Comprehensive Income.” This ASU allows an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendment no longer allows an entity to show changes to other comprehensive income solely through the statement of equity. For publicly traded entities, the guidance is effective for annual and interim reporting periods beginning on or after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12, which defers only those changes in ASU 2011-05 that relate to the presentation of reclassification adjustments. Our adoption of this guidance did not have a material impact on our financial condition, results of operations, cash flows or financial disclosures.
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| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
Market risk is the potential for loss due to a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on borrowings under the Credit Facilities and commercial paper program. Interest on borrowings under the Credit Facilities is at an agreed upon percentage point spread over LIBOR, or a base rate stated in the agreement. At December 31, 2012, we had $340 million in borrowings outstanding under our commercial paper program, which is supported by the Credit Facilities. Assuming our current level of debt, a change in LIBOR rates of 1 percent would increase our interest charges by approximately $3 million per year.
We maintain certain debt instruments at a fixed rate whose fair value will fluctuate based on changes in interest rates and market perceptions of our credit risk. The fair value of our total debt was $5.1 billion and $4.3 billion at December 31, 2012 and 2011, respectively. The increase was primarily a result of our issuance of $1.2 billion in debt in February 2012, partially offset by the net repayment of $635 million on our Credit Facilities coupled with changes in fair value related to changes in interest rates and market perceptions of our credit risk.
Foreign Currency Risk
Although we are a Swiss corporation, we define foreign currency as any non-U.S. denominated currency. Our functional currency is primarily the U.S. Dollar, which is consistent with the oil and gas industry. However, outside the United States, some of our expenses are incurred in local currencies. Therefore, when the U.S. Dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in U.S. Dollars will increase (decrease).
We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currency that are other than the functional currency. To help manage this potential risk, we periodically enter into derivative instruments to manage our exposure to fluctuations in currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the Consolidated Balance Sheet and in “Accumulated other comprehensive loss” (“AOCL”). Amounts recorded in AOCL are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Our North Sea and Brazil operations have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we have historically maintained short-term forward contracts settling monthly in their respective local currencies. At December 31, 2012, we had no outstanding derivative contracts. At December 31, 2011, total unrealized loss related to forward contracts was $3 million, which was recorded as part of AOCL in our Consolidated Balance Sheet. Depending on market conditions, we may elect to utilize short-term forward currency contracts in the future.
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Market Risk
We sponsor the Noble Drilling Corporation 401(k) Savings Restoration Plan (“Restoration Plan”). The Restoration Plan is a nonqualified, unfunded employee benefit plan under which certain highly compensated employees may elect to defer compensation in excess of amounts deferrable under our 401(k) savings plan. The Restoration Plan has no assets, and amounts withheld for the Restoration Plan are kept by us for general corporate purposes. The investments selected by employees and the associated returns are tracked on a phantom basis. Accordingly, we have a liability to employees for amounts originally withheld plus phantom investment income or less phantom investment losses. We are at risk for phantom investment income and, conversely, benefit should phantom investment losses occur. At December 31, 2012, our liability under the Restoration Plan totaled $7 million. We have purchased investments that closely correlate to the investment elections made by participants in the Restoration Plan in order to mitigate the impact of the phantom investment income and losses on our consolidated financial statements. The value of these investments held for our benefit totaled $6 million at December 31, 2012. A 10 percent change in the fair value of the phantom investments would change our liability by approximately $0.6 million. Any change in the fair value of the phantom investments would be mitigated by a change in the investments held for our benefit.
We also have a U.S. noncontributory defined benefit pension plan that covers certain salaried employees and a U.S. noncontributory defined benefit pension plan that covers certain hourly employees, whose initial date of employment is prior to August 1, 2004 (collectively referred to as our “qualified U.S. plans”). These plans are governed by the Noble Drilling Corporation Retirement Trust (the “Trust”). The benefits from these plans are based primarily on years of service and, for the salaried plan, employees’ compensation near retirement. These plans are designed to qualify under the Employee Retirement Income Security Act of 1974 (“ERISA”), and our funding policy is consistent with funding requirements of ERISA and other applicable laws and regulations. We make cash contributions, or utilize credits available to us, for the qualified U.S. plans when required. The benefit amount that can be covered by the qualified U.S. plans is limited under ERISA and the Internal Revenue Code (“IRC”) of 1986. Therefore, we maintain an unfunded, nonqualified excess benefit plan designed to maintain benefits for all employees at the formula level in the qualified salary U.S. plan. We refer to the qualified U.S. plans and the excess benefit plan collectively as the “U.S. plans”.
In addition to the U.S. plans, each of Noble Drilling (Land Support) Limited, Noble Enterprises Limited and Noble Drilling (Nederland) B.V., all indirect, wholly-owned subsidiaries of Noble-Swiss, maintains a pension plan that covers all of its salaried, non-union employees (collectively referred to as our “non-U.S. plans”). Benefits are based on credited service and employees’ compensation near retirement, as defined by the plans.
Changes in market asset value related to the pension plans noted above could have a material impact upon our Consolidated Statements of Comprehensive Income and could result in material cash expenditures in future periods.
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| Item 8. | Financial Statements and Supplementary Data. |
The following financial statements are filed in this Item 8:
| Page | ||||
| Report of Independent Registered Public Accounting Firm (Noble-Swiss) |
46 | |||
| 47 | ||||
| 48 | ||||
| 49 | ||||
| 50 | ||||
| 51 | ||||
| Report of Independent Registered Public Accounting Firm (Noble-Cayman) |
52 | |||
| 53 | ||||
| 54 | ||||
| 55 | ||||
| 56 | ||||
| 57 | ||||
| 58 | ||||
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Shareholders of Noble Corporation, a Swiss Corporation (“Noble-Swiss”)
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and cash flows present fairly, in all material respects, the financial position of Noble-Swiss and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Noble-Swiss’ management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on Noble-Swiss’ internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2013
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NOBLE CORPORATION (NOBLE-SWISS) AND SUBSIDIARIES
(In thousands)
| December 31, | December 31, | |||||||
| 2012 | 2011 | |||||||
| ASSETS |
|
|||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 282,092 | $ | 239,196 | ||||
| Accounts receivable |
743,673 | 587,163 | ||||||
| Taxes receivable |
112,423 | 75,284 | ||||||
| Prepaid expenses |
43,962 | 35,796 | ||||||
| Other current assets |
123,175 | 122,173 | ||||||
|
|
|
|
|
|||||
| Total current assets |
1,305,325 | 1,059,612 | ||||||
|
|
|
|
|
|||||
| Property and equipment |
||||||||
| Drilling equipment and facilities |
16,777,013 | 15,243,861 | ||||||
| Other |
194,653 | 197,485 | ||||||
|
|
|
|
|
|||||
| 16,971,666 | 15,441,346 | |||||||
| Accumulated depreciation |
(3,945,694 | ) | (3,311,001 | ) | ||||
|
|
|
|
|
|||||
| 13,025,972 | 12,130,345 | |||||||
|
|
|
|
|
|||||
| Other assets |
276,477 | 305,202 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 14,607,774 | $ | 13,495,159 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND EQUITY |
||||||||
| Current liabilities |
||||||||
| Accounts payable |
$ | 350,147 | $ | 436,006 | ||||
| Accrued payroll and related costs |
132,728 | 117,907 | ||||||
| Interest payable |
68,436 | 54,419 | ||||||
| Taxes payable |
135,257 | 94,920 | ||||||
| Dividends payable |
66,369 | — | ||||||
| Other current liabilities |
158,512 | 123,928 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
911,449 | 827,180 | ||||||
|
|
|
|
|
|||||
| Long-term debt |
4,634,375 | 4,071,964 | ||||||
| Deferred income taxes |
226,045 | 242,791 | ||||||
| Other liabilities |
347,615 | 255,372 | ||||||
|
|
|
|
|
|||||
| Total liabilities |
6,119,484 | 5,397,307 | ||||||
|
|
|
|
|
|||||
| Commitments and contingencies |
||||||||
| Equity |
||||||||
| Shares; 253,348 shares and 252,639 shares outstanding |
710,130 | 766,595 | ||||||
| Treasury shares, at cost; 589 shares and 287 shares |
(21,069 | ) | (10,553 | ) | ||||
| Additional paid-in capital |
83,531 | 48,356 | ||||||
| Retained earnings |
7,066,023 | 6,676,444 | ||||||
| Accumulated other comprehensive loss |
(115,449 | ) | (74,321 | ) | ||||
|
|
|
|
|
|||||
| Total shareholders’ equity |
7,723,166 | 7,406,521 | ||||||
|
|
|
|
|
|||||
| Noncontrolling interests |
765,124 | 691,331 | ||||||
| Total equity |
8,488,290 | 8,097,852 | ||||||
|
|
|
|
|
|||||
| Total liabilities and equity |
$ | 14,607,774 | $ | 13,495,159 | ||||
|
|
|
|
|
|||||
See accompanying notes to the consolidated financial statements.
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NOBLE CORPORATION (NOBLE-SWISS) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Operating revenues |
||||||||||||
| Contract drilling services |
$ | 3,349,362 | $ | 2,556,758 | $ | 2,695,493 | ||||||
| Reimbursables |
115,495 | 79,195 | 76,831 | |||||||||
| Labor contract drilling services |
81,890 | 59,004 | 32,520 | |||||||||
| Other |
265 | 875 | 2,332 | |||||||||
|
|
|
|
|
|
|
|||||||
| 3,547,012 | 2,695,832 | 2,807,176 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Operating costs and expenses |
||||||||||||
| Contract drilling services |
1,776,481 | 1,384,200 | 1,177,800 | |||||||||
| Reimbursables |
94,096 | 58,439 | 59,414 | |||||||||
| Labor contract drilling services |
46,895 | 33,885 | 22,056 | |||||||||
| Depreciation and amortization |
758,621 | 658,640 | 539,829 | |||||||||
| Selling, general and administrative |
99,990 | 91,377 | 91,997 | |||||||||
| Loss on impairment |
20,384 | — | — | |||||||||
| Gain on contract settlements/extinguishments, net |
(33,255 | ) | (21,202 | ) | — | |||||||
|
|
|
|
|
|
|
|||||||
| 2,763,212 | 2,205,339 | 1,891,096 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
783,800 | 490,493 | 916,080 | |||||||||
| Other income (expense) |
||||||||||||
| Interest expense, net of amount capitalized |
(85,763 | ) | (55,727 | ) | (9,457 | ) | ||||||
| Interest income and other, net |
5,188 | 1,484 | 9,886 | |||||||||
|
|
|
|
|
|
|
|||||||
| Income before income taxes |
703,225 | 436,250 | 916,509 | |||||||||
| Income tax provision |
(147,088 | ) | (72,625 | ) | (143,077 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Net income |
556,137 | 363,625 | 773,432 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net loss (income) attributable to noncontrolling interests |
(33,793 | ) | 7,273 | (3 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Net income attributable to Noble Corporation |
$ | 522,344 | $ | 370,898 | $ | 773,429 | ||||||
|
|
|
|
|
|
|
|||||||
| Net income per share attributable to Noble Corporation |
||||||||||||
| Basic |
$ | 2.05 | $ | 1.46 | $ | 3.03 | ||||||
| Diluted |
2.05 | 1.46 | 3.02 | |||||||||
| Weighted-Average Shares Outstanding: |
||||||||||||
| Basic |
252,435 | 251,405 | 253,123 | |||||||||
| Diluted |
252,791 | 251,989 | 253,936 | |||||||||
See accompanying notes to the consolidated financial statements.
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NOBLE CORPORATION (NOBLE-SWISS) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net income |
$ | 556,137 | $ | 363,625 | $ | 773,432 | ||||||
| Other comprehensive income (loss), net of tax |
||||||||||||
| Foreign currency translation adjustments |
(8,076 | ) | (2,566 | ) | 2,456 | |||||||
| Gain (loss) on foreign currency forward contracts |
3,061 | (4,665 | ) | 1,187 | ||||||||
| Gain (loss) on interest rate swaps |
— | (366 | ) | 366 | ||||||||
| Net pension plan loss (net of a tax benefit of $3,777 in 2012, $12,845 in 2011 and $2,888 in 2010) |
(41,658 | ) | (18,551 | ) | (1,898 | ) | ||||||
| Amortization of deferred pension plan amounts (net of tax provision of $2,841 in 2012, $1,146 in 2011 and $1,286 in 2010) |
5,545 | 2,047 | 2,550 | |||||||||
|
|
|
|
|
|
|
|||||||
| Other comprehensive income (loss), net |
(41,128 | ) | (24,101 | ) | 4,661 | |||||||
|
|
|
|
|
|
|
|||||||
| Total comprehensive income |
515,009 | 339,524 | 778,093 | |||||||||
| Less: Loss (income) attributable to noncontrolling interests |
(33,793 | ) | 7,273 | (3 | ) | |||||||
| Less: Noncontrolling portion of gain (loss) on interest rate swaps |
— | 183 | (183 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income attributable to Noble Corporation |
$ | 481,216 | $ | 346,980 | $ | 777,907 | ||||||
|
|
|
|
|
|
|
|||||||
See accompanying notes to the consolidated financial statements.
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NOBLE CORPORATION (NOBLE-SWISS) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Cash flows from operating activities |
||||||||||||
| Net income |
$ | 556,137 | $ | 363,625 | $ | 773,432 | ||||||
| Adjustments to reconcile net income to net cash from operating activities: |
||||||||||||
| Depreciation and amortization |
758,621 | 658,640 | 539,829 | |||||||||
| Loss on impairment |
20,384 | — | — | |||||||||
| Gain on contract extinguishments, net |
— | (21,202 | ) | — | ||||||||
| Deferred income taxes |
(20,119 | ) | (82,325 | ) | (41,409 | ) | ||||||
| Amortization of share-based compensation |
35,930 | 31,904 | 34,930 | |||||||||
| Net change in other assets and liabilities |
30,740 | (210,402 | ) | 330,120 | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash from operating activities |
1,381,693 | 740,240 | 1,636,902 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash flows from investing activities |
||||||||||||
| Capital expenditures |
(1,669,811 | ) | (2,621,235 | ) | (1,406,010 | ) | ||||||
| Change in accrued capital expenditures |
(121,077 | ) | 81,047 | 139,185 | ||||||||
| Refund from contract extinguishments |
— | 18,642 | — | |||||||||
| Acquisition of FDR Holdings, Ltd., net of cash acquired |
— | — | (1,629,644 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash from investing activities |
(1,790,888 | ) | (2,521,546 | ) | (2,896,469 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Cash flows from financing activities |
||||||||||||
| Net change in borrowings on bank credit facilities |
(635,192 | ) | 935,000 | 40,000 | ||||||||
| Proceeds from issuance of senior notes, net of debt issuance costs |
1,186,636 | 1,087,833 | 1,238,074 | |||||||||
| Contributions from joint venture partners |
40,000 | 536,000 | 35,000 | |||||||||
| Payments of joint venture debt |
— | (693,494 | ) | — | ||||||||
| Settlement of interest rate swaps |
— | (29,032 | ) | (6,186 | ) | |||||||
| Financing costs on credit facilities |
(5,221 | ) | (2,835 | ) | — | |||||||
| Proceeds from employee stock transactions |
14,677 | 9,924 | 11,828 | |||||||||
| Repurchases of employee shares surrendered for taxes |
(10,516 | ) | (10,233 | ) | (10,116 | ) | ||||||
| Par value reduction/dividend payments |
(138,293 | ) | (150,532 | ) | (227,325 | ) | ||||||
| Repurchases of shares |
— | — | (219,330 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash from financing activities |
452,091 | 1,682,631 | 861,945 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net change in cash and cash equivalents |
42,896 | (98,675 | ) | (397,622 | ) | |||||||
| Cash and cash equivalents, beginning of period |
239,196 | 337,871 | 735,493 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash and cash equivalents, end of period |
$ | 282,092 | $ | 239,196 | $ | 337,871 | ||||||
|
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|
|
|
|
|
|||||||
See accompanying notes to the consolidated financial statements.
50
Table of Contents
NOBLE CORPORATION (NOBLE-SWISS) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
| Accumulated | ||||||||||||||||||||||||||||||||
| Capital in | Other | |||||||||||||||||||||||||||||||
| Shares | Excess of | Retained | Treasury | Noncontrolling | Comprehensive | Total | ||||||||||||||||||||||||||
| Balance | Par Value | Par Value | Earnings | Shares | Interests | Loss | Equity | |||||||||||||||||||||||||
| Balance at January 1, 2010 |
261,975 | $ | 1,130,607 | $ | — | $ | 5,855,737 | $ | (143,031 | ) | $ | — | $ | (54,881 | ) | $ | 6,788,432 | |||||||||||||||
| Employee related equity activity |
||||||||||||||||||||||||||||||||
| Amortization of share-based compensation |
— | — | 34,930 | — | — | — | — | 34,930 | ||||||||||||||||||||||||
| Issuance of share-based compensation shares |
86 | 343 | (117 | ) | — | — | — | — | 226 | |||||||||||||||||||||||
| Exercise of stock options |
538 | 2,119 | 9,483 | — | — | — | — | 11,602 | ||||||||||||||||||||||||
| Tax benefit of stock options exercised |
— | — | 6,494 | — | — | — | — | 6,494 | ||||||||||||||||||||||||
| Restricted shares forfeited or repurchased for taxes |
(184 | ) | (809 | ) | 965 | 1,334 | (11,606 | ) | — | — | (10,116 | ) | ||||||||||||||||||||
| Repurchases of shares |
— | — | — | — | (219,330 | ) | — | — | (219,330 | ) | ||||||||||||||||||||||
| Net income |
— | — | — | 773,429 | — | 3 | — | 773,432 | ||||||||||||||||||||||||
| Par value reduction/dividend payments |
— | (214,576 | ) | (12,749 | ) | — | — | — | — | (227,325 | ) | |||||||||||||||||||||
| Noncontrolling interests from FDR Holdings, Ltd. acquisition |
— | — | — | — | — | 124,628 | — | 124,628 | ||||||||||||||||||||||||
| Other comprehensive income, net |
— | — | — | — | — | — | 4,661 | 4,661 | ||||||||||||||||||||||||
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|||||||||||||||||
| Balance at December 31, 2010 |
262,415 | $ | 917,684 | $ | 39,006 | $ | 6,630,500 | $ | (373,967 | ) | $ | 124,631 | $ | (50,220 | ) | $ | 7,287,634 | |||||||||||||||
| Employee related equity activity |
||||||||||||||||||||||||||||||||
| Amortization of share-based compensation |
— | — | 31,904 | — | — | — | — | 31,904 | ||||||||||||||||||||||||
| Issuance of share-based compensation shares |
252 | 848 | (838 | ) | — | — | — | — | 10 | |||||||||||||||||||||||
| Exercise of stock options |
501 | 1,661 | 7,303 | — | — | — | — | 8,964 | ||||||||||||||||||||||||
| Tax benefit of stock options exercised |
— | — | 950 | — | — | — | — | 950 | ||||||||||||||||||||||||
| Restricted shares forfeited or repurchased for taxes |
(413 | ) | (1,401 | ) | 1,401 | — | (10,233 | ) | — | — | (10,233 | ) | ||||||||||||||||||||
| Retirement of treasury shares |
(10,116 | ) | (33,035 | ) | — | (340,612 | ) | 373,647 | — | — | — | |||||||||||||||||||||
| Settlement of FIN 48 provision |
— | — | — | 15,658 | — | — | — | 15,658 | ||||||||||||||||||||||||
| Net income |
— | — | — | 370,898 | — | (7,273 | ) | — | 363,625 | |||||||||||||||||||||||
| Equity contribution by joint venture partner |
— | — | — | — | — | 573,973 | — | 573,973 | ||||||||||||||||||||||||
| Par value reduction payments |
— | (119,162 | ) | (31,370 | ) | — | — | — | — | (150,532 | ) | |||||||||||||||||||||
| Other comprehensive loss, net |
— | — | — | — | — | — | (24,101 | ) | (24,101 | ) | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Balance at December 31, 2011 |
252,639 | $ | 766,595 | $ | 48,356 | $ | 6,676,444 | $ | (10,553 | ) | $ | 691,331 | $ | (74,321 | ) | $ | 8,097,852 | |||||||||||||||
| Employee related equity activity |
||||||||||||||||||||||||||||||||
| Amortization of share-based compensation |
— | — | 35,930 | — | — | — | — | 35,930 | ||||||||||||||||||||||||
| Issuance of share-based compensation shares |
437 | 1,307 | (1,299 | ) | — | — | — | — | 8 | |||||||||||||||||||||||
| Exercise of stock options |
646 | 1,836 | 11,705 | — | — | — | — | 13,541 | ||||||||||||||||||||||||
| Tax benefit of stock options exercised |
— | — | 1,128 | — | — | — | — | 1,128 | ||||||||||||||||||||||||
| Restricted shares forfeited or repurchased for taxes |
(374 | ) | (1,138 | ) | 1,138 | — | (10,516 | ) | — | — | (10,516 | ) | ||||||||||||||||||||
| Net income |
— | — | — | 522,344 | — | 33,793 | — | 556,137 | ||||||||||||||||||||||||
| Equity contribution by joint venture partner |
— | — | — | — | — | 40,000 | — | 40,000 | ||||||||||||||||||||||||
| Par value reduction/dividend payments |
— | (58,470 | ) | (13,427 | ) | (66,396 | ) | — | — | — | (138,293 | ) | ||||||||||||||||||||
| Dividends pa | ||||||||||||||||||||||||||||||||