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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
     
(MARK ONE)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    FOR THE TRANSITION PERIOD FROM          TO          
 
COMMISSION FILE NUMBER 1-7573
PARKER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
 
     
Delaware   73-0618660
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
5 Greenway Plaza,
Suite 100, Houston, Texas
(Address of principal executive offices)
  77046
(Zip code)
 
Registrant’s telephone number, including area code:
(281) 406-2000
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered:
 
Common Stock, par value $0.162/3 per share   New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o  No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o  No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ  No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No o
 
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.  o
 
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. (Check one):
 
             
Large accelerated filer o
  Accelerated filer þ   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o  No þ
 
The aggregate market value of our common stock held by non-affiliates on June 30, 2010 was $446.3 million. At February 18, 2011, there were 116,408,639 shares of common stock issued and outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of our definitive proxy statement for the Annual Meeting of Shareholders to be held on May 5, 2011 are incorporated by reference in Part III.
 


 

 
TABLE OF CONTENTS
 
             
        Page
 
PART I
Item 1.   Business     3  
Item 1A.   Risk Factors     14  
Item 1B.   Unresolved Staff Comments     28  
Item 2.   Properties     28  
Item 3.   Legal Proceedings     31  
 
PART II
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     32  
Item 6.   Selected Financial Data     33  
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations     34  
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk     50  
Item 8.   Financial Statements and Supplementary Data     52  
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     92  
Item 9A.   Controls and Procedures     92  
Item 9B.   Other Information     93  
 
PART III
Item 10.   Directors, Executive Officers and Corporate Governance     93  
Item 11.   Executive Compensation     93  
Item 12.   Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters     93  
Item 13.   Certain Relationships and Related Transactions, and Director Independence     93  
Item 14.   Principal Accounting Fees and Services     94  
 
PART IV
Item 15.   Exhibits and Financial Statement Schedules     94  
Signatures     99  
 EX-10.4
 EX-10.18
 EX-10.19
 EX-10.21
 EX-10.28
 EX-21
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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PART I
 
ITEM 1.   BUSINESS
 
General
 
Unless otherwise indicated, the terms “Company,” “we,” “us” and “our” refer to Parker Drilling Company together with its subsidiaries and “Parker Drilling” refers solely to the parent, Parker Drilling Company. Parker Drilling Company was incorporated in the state of Oklahoma in 1954 after having been established in 1934. In March 1976, the state of incorporation of the Company was changed to Delaware through the merger of the Oklahoma corporation into its wholly-owned subsidiary Parker Drilling Company, a Delaware corporation. Our principal executive offices are located at 5 Greenway Plaza, Suite 100, Houston, Texas 77046.
 
We are an international provider of contract drilling and drilling-related services currently operating in 12 countries. We have operated in 53 foreign countries and the United States since beginning operations in 1934, making us among the most geographically experienced drilling contractors in the world. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. We believe our quality, health, safety and environmental practices are among the leaders in our industry.
 
Our 2010 revenues were derived from the following five segments:
 
  •  International Drilling
 
  •  U.S. Drilling
 
  •  Rental Tools
 
  •  Project Management and Engineering Services
 
  •  Construction Contract
 
Our Rig Fleet
 
The diversity of our rig fleet, both in terms of geographic location and asset class, enables us to provide a broad range of services to oil and gas operators worldwide. As of December 31, 2010, our available fleet of rigs consisted of:
 
  •  11 rigs in the Commonwealth of Independent States/Africa-Middle East (CIS/AME) region, including 8 land rigs and 1 arctic-class barge rig in Kazakhstan and 2 land rigs in Algeria
 
  •  10 rigs in the Americas region, including 7 land rigs and 1 barge rig in Mexico and 2 land rigs in Colombia
 
  •  5 land rigs in the Asia Pacific region, including 2 rigs in Indonesia, 1 rig in Papua New Guinea and 2 rigs in New Zealand. Three additional rigs, located in this region, were classified as assets held for sale as of December 31, 2010
 
  •  13 barge drilling rigs in the inland shallow waters of the U.S. Gulf of Mexico (GOM)
 
  •  1 unassigned land rig currently held in our yard in New Iberia, Louisiana.
 
In 2008, we began the construction of two newbuild land rigs designed to operate in the Alaskan environment. These rigs are expected to be delivered to Alaska in mid-2011. We anticipate drilling operations will commence in late 2011 upon final acceptance of the two rigs by our customer, BP.
 
Our International Drilling Business
 
The international drilling markets in which we operate have one or more of the following characteristics:
 
  •  customers who typically are major independent and national oil and gas companies and integrated service providers;


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  •  drilling programs in remote locations with little infrastructure and/or harsh environments requiring specialized drilling equipment with a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;
 
  •  complex wells (i.e., high pressure, deep depths, hazardous or geologically challenging) requiring specialized equipment and considerable experience to drill; and
 
  •  international contracts that generally cover periods of one year or more.
 
Our Rental Tools Business
 
We provide premium rental tools for land and offshore oil and gas drilling and workover activities, offering a full line of drill pipe, drill collars, tubing, high- and low-pressure blowout preventers, choke manifolds, junk and cement mills and casing scrapers. The base of operations for our rental tools business is in New Iberia, Louisiana. Other facilities where we hold an inventory of rental tools and provide service to our customers are located in Texas, Wyoming, North Dakota and Pennsylvania.
 
Our current market for rental tools is primarily U.S. land drilling, a cyclical market driven by commodity pricing and availability of project financing. The increase in unconventional lateral or horizontal drilling, often used in drilling shale formations, has added to the market demand for rental tools, keeping our current market focus in the regions of the primary shale plays.
 
Our principal customers are major and independent oil and gas exploration and production companies operating in the U.S. energy producing markets on land and in the GOM. Generally, tools are used for only a portion of a well drilling program and are requested by the customer at the time they are needed. As a result, they are usually rented on a daily or monthly basis, requiring us to keep a broad inventory of tools in stock. Approximately 15 percent of revenues from our rental tools business are derived from equipment used in offshore and coastal water operations of the GOM. In addition, from our locations within the United States, we provide tool rentals to customers operating internationally in countries including Angola, Brazil, Canada, Chad, Congo, Egypt, Equatorial Guinea, Libya, Mexico, Russia and the United Arab Emirates. During the years ended December 31, 2010, 2009 and 2008, approximately 5 percent, 9 percent and 2 percent of Rental Tools’ revenues were derived from equipment used in international applications, respectively.
 
Our Project Management and Engineering Services Business
 
We provide non-capital intensive services such as Front End Engineering and Design (FEED), Engineering, Procurement, Construction and Installation (EPCI), Operations and Maintenance (O&M), and other project management services (e.g., labor, maintenance, logistics, etc.) for operators who own their own drilling rigs and who choose to engage our technical expertise to perform contracted services. We have ongoing O&M and project management activities in Alaska, Kuwait and Sakhalin Island, Russia. We are also currently involved in one pre-FEED study project and are in the detailed engineering and procurement phase of the Arkutun Dagi project for Exxon Neftegas Limited (ENL).
 
Our Construction Contract Business
 
In 2008, we commenced the construction phase of the BP-owned Liberty extended reach drilling rig project. We believe the Liberty rig is one of the most technologically advanced drilling rigs in the world, designed to drill ultra-extended reach wells nearly two miles deep and eight miles out from the drilling pad. The rig is currently in place on a satellite drilling island in Alaska. In November 2010, our customer, BP, suspended construction of the rig while it reviews the rig’s engineering and design, including its safety systems. For more information, see Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
 
In August 2009, Parker Drilling Arctic Operating, Inc. was awarded the O&M contract for the BP-owned Liberty rig, a land-based rig targeting the Liberty field. However, as noted above, in November 2010, BP suspended construction of the rig while it reviews the rig’s engineering and design, including its safety systems. The O&M contract will expire on June 1, 2011, unless extended. For more information, see Part II, Item 7 — Management’s


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Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
 
Our U.S. Gulf of Mexico and Inland Waterways Business
 
The drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by current oil and natural gas prices and availability of project financing. Within this area, we operate barge rigs in the shallow waters in and along the inland waterways and coasts of Louisiana and Texas. Our rigs drill for natural gas, oil and a combination of oil and natural gas. Contract terms are typically well-to-well, with durations averaging 30 to 150 days. During periods of strong market demand, typically driven by high commodity prices, contract drilling terms can extend up to twelve months and longer.
 
During 2010, the drilling industry was impacted by the Macondo well fire and ensuing oil spill in the U.S. Gulf of Mexico. The drilling moratorium that followed had marginal impact on our barge drilling permit process, however, additional regulatory compliance enacted required us to accelerate certain upgrades already being made to the fleet in order to fully comply with the newly adopted regulatory requirements.
 
Our Strategy
 
Our strategy is to achieve and maintain market leadership in selected international markets as a provider of drilling and drilling-related services and products that include, rental tools, and project management and engineering services to the energy industry; to grow our business through selective investments in new assets and lines of businesses; to differentiate our brand by leveraging our core competencies, or “four pillars” as described below; to provide best value solutions; and to exercise financial discipline. Key elements of our strategy include:
 
Achieving and Maintaining Market Leadership.  We believe we achieve and sustain the preference for our barge and land rigs by building, upgrading and maintaining a fleet of rigs that we expect to be preferred by operators because of their quality and dependability, and through placing those rigs in areas we believe present long-term oil and natural gas development opportunities. By original design or through upgrades, we offer rigs capable of efficient, safe and economic performance for customers operating in select locations throughout the world, including those in difficult, hazardous or environmentally sensitive areas.
 
Growing Through Selective Investment.  We believe we can improve our competitive position and financial performance through investments in new assets or lines of business that complement and expand our capabilities. We are focused on:
 
  •  expanding and broadening our non-capital intensive project management and engineering services activities by leveraging our experience
 
  •  growing our rental tools operation by locating new service facilities in markets with growing demand from new and existing customers
 
  •  adding new equipment to our drilling rig fleet that improves opportunities with operators
 
  •  entering new markets that align with the products and services we offer.
 
Differentiating our Brand.  We differentiate ourselves from other providers of similar services by focusing on our core competencies, or “four pillars”: safety, training, technology and performance. We seek to provide our customers increased performance, innovation in our services, and safe and efficient operations through these four pillars as follows:
 
Safety:  We believe industry-leading safety performance is a crucial factor in our status as a preferred drilling contractor and rental tools supplier. We have a portfolio of metrics and processes we apply to reinforce and continually improve our safety and environmental performance.
 
Training:  The challenges of our business are magnified when considering the technological requirements of our work. We have invested significant resources to provide a full curriculum of standardized training in multiple languages to overcome barriers to working safely and operating efficiently.


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Technology:  We have a 76-year legacy of developing new technologies for drilling in frontier environments. Our rigs continue to set numerous records worldwide, including drilling some of the longest-reaching wells. Developing new technology to create greater efficiencies in the drilling process lies at the heart of our competitive edge. We continually look for and evaluate new technologies that have the potential to, among other things, improve drilling efficiency, minimize environmental impacts, and enhance safety.
 
Performance:  A primary aim is to provide services that benefit both our customers and our company. We strive to achieve this by planning, executing and measuring our performance against our goals and our customers’ expectations. We utilize performance metrics in our business and regularly share them with our customers. Our planned maintenance programs, including preventive maintenance to facilitate dependable operating efficiency and minimize down time, helps to establish us as a contractor of choice.
 
Maintaining Financial Discipline.  We strive to maintain strong financial controls and disciplines in all aspects of our business to ensure that our internal assessment of projects and plans adhere to solid financial principles. Our operating philosophy emphasizes continuous improvement of processes, equipment standardization, global quality, safety, supply chain management, and vigilance in monitoring and controlling costs. Capital expenditures are aligned with core objectives. These principles are intended to lead to stronger-than-peer financial performance in terms of capital utilization and generation of value to our shareholders while allowing operational effectiveness.
 
2010 Strategic Actions
 
In 2010 the following actions, among others, were the direct result of implementing the strategy discussed above:
 
  •  The Yastreb rig, which was designed, built and operated by us for ENL, operator of the Sakhalin-1 Project, set a new world record for extended-reach drilling with the Odoptu OP-11 well. OP-11 achieved a total measured depth of 40,502 feet (7.67 miles). OP-11 also set a world record with a horizontal reach of 37,648 feet (7.13 miles) under the sea floor. As our customers take the search for oil and gas into frontier regions, we believe that this kind of expertise will become more valued in the years ahead.
 
  •  We infused our rental tools business with approximately $49 million in capital investments, most of which went directly for new equipment to serve the increased demand for rental tools created by the growth in U.S. unconventional shale drilling.
 
  •  We hold the number one position in the U.S. Gulf of Mexico barge drilling market measured by barge rigs working. According to industry compiled information, over 50 percent of all wells drilled by barge rigs in the shallow waters of the Gulf of Mexico during 2010 were drilled by Parker rigs.
 
  •  In our International Drilling segment:
 
  four drilling contracts in the Americas region were extended into 2012.
 
  three new contracts in our Asia Pacific region, one of which mobilized a rig that had been ready-stacked since 2009
 
  our Caspian Sea arctic barge contract was extended into 2012.
 
Our Competitive Strengths
 
Our competitive strengths have historically contributed to our operating performance and we believe the following strengths enhance our outlook for the future:
 
Outstanding Safety, Planned Maintenance, Inventory Control and Training Programs.  We continue to have an outstanding safety record. In 2010, our Total Recordable Incident Rate (TRIR) was 23% ahead of our targeted goal with 93% of our facilities reporting Incident Free Operations (IFO). Our safety record, as evidenced by our low TRIR, and IFO results has made us one of the leaders in occupational injury prevention.


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Our TRIR has been below the industry average for each of the last ten years, with rates less than half the industry average since 2004. Our safety and training programs also contain consideration of environmental safety and conservation, helping us avoid environmental incidents. We believe that this safety record, along with integrated quality, safety maintenance and supply chain management programs, has contributed to our success in obtaining drilling contracts, as well as contracts to manage and provide labor resources for drilling rigs owned by third parties. Our training centers in Louisiana, Alaska and New Zealand provide safety and technical training curricula in four different languages and provide regulatory compliance training throughout the world.
 
Geographically Targeted Operations and Assets.  We currently maintain, operate or manage rigs in Algeria, Colombia, Indonesia, Kazakhstan, Kuwait, Mexico, New Zealand, Russia, Papua New Guinea and the United States. In addition, we operate rental tool stores in seven targeted locations in the U.S. We have operated in 53 foreign countries and the United States, making us among the most geographically experienced drilling contractors in the world. Our international revenues, including drilling, project management and engineering services provided in international locations, comprised 45 percent of our total revenues for the year ended December 31, 2010.
 
Technological Leadership.  We have a demonstrated history of technological leadership within the drilling industry. Our previous contributions to the industry include the patented heli-hoist rig design, winterized rigs on wheels for arctic drilling, and an arctic-class barge rig to explore the Caspian Sea. We have established extended reach drilling depth records on several occasions, the latest achieved in December 2010 with the Yastreb rig drilling at Sakhalin Island, Russia. This well reached 40,502 feet — approximately seven and two-thirds miles — in total measured depth as it drilled under the sea floor to access the Odoptu field for ENL’s Sakhalin-1 project.
 
Strong and Experienced Senior Management Team.  Our management team has extensive experience in the contract drilling industry. Our executive chairman, Robert L. Parker Jr., joined the Company in 1973 and served as our president from 1977 through June 2007, chief executive officer from 1991 until October 2009, and has been a director since 1973. Under the leadership of Mr. Parker Jr. we have continued our reputation as a leading worldwide provider of contract drilling services. David C. Mannon, our president and chief executive officer and member of the board of directors since October 2009, joined our senior management team in late 2004 as senior vice president and chief operating officer and was appointed president in July 2007. Prior to joining our company, Mr. Mannon served in various managerial positions, culminating with his appointment as president and chief executive officer for Triton Engineering Services Company, a subsidiary of Noble Drilling. He brings a broad range of nearly 30 years of industry experience to his role. Our chief financial officer, W. Kirk Brassfield, joined the Company in 1998 and has served in several executive positions including vice president, controller and principal accounting officer. He brings 30 years of experience to the management team, including 20 years in the energy industry. Philip Agnew, vice president of Technical Services, joined the company in late 2010, bringing with him more than 20 years of experience in design, construction and project management expertise.
 
Project Management.  We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we manage two drilling operations for the ENL Sakhalin-1 project, the Yastreb land rig and the Orlan platform. We designed, constructed and provided the Yastreb land rig to ENL and continue to manage drilling operations under a multi-year O&M contract. We also operate the Orlan platform under a multi-year O&M contract for ENL.
 
We also provide management and technical services in addition to labor services on third party-owned drilling rigs in Kuwait and have provided similar services for other operators in the past.
 
Customers
 
Our customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2010, our two largest customers, BP and ExxonMobil (including subsidiaries and joint ventures of each), accounted for approximately 12.4 percent and 11.6 percent of our total revenues, respectively. Our revenues associated with BP are primarily for the construction of the BP-owned Liberty rig. Our revenues from ExxonMobil


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are primarily for drilling-related services. Our ten most significant customers collectively accounted for approximately 58.0 percent of our total revenues in 2010.
 
Competition
 
The contract drilling industry is a highly competitive business characterized by high capital requirements and challenges in securing and retaining qualified field personnel.
 
In international land markets, we compete with a number of international drilling contractors as well as smaller local contractors. Most contracts are awarded on a competitive bidding basis and operators often consider technical expertise and quality of equipment in addition to price. Although local drilling contractors typically have lower labor and mobilization costs, we are generally able to distinguish ourselves from these companies based on our technical expertise, safety performance, quality of our equipment, planned maintenance and experience. In international markets, our experience in operating in challenging environments has been a significant factor in securing contracts. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future (See also Item 1A — Risk Factors).
 
In the GOM barge drilling markets, we are awarded most contracts through a competitive bidding process. We have achieved some success in differentiating ourselves from competitors through our upgraded fleet, planned maintenance programs and general strategy to ready-stack rigs, a standby mode of operational readiness where our support costs are reduced while the equipment is maintained in a near market-ready condition for quick return to operations. This strategy can result in safer and more efficient operations.
 
We believe that our rental tools business, Quail Tools, L.P., is one of the leading rental tools companies in the U.S. oil and gas drilling markets. Quail Tools competes against other rental tool companies based on price and quality of service.
 
A number of our customers have been seeking to establish exploration or development drilling programs based on partnering relationships or alliances with a limited number of preferred drilling contractors. Such relationships can result in longer-term work and higher efficiencies that increase profitability for drilling contractors and result in a lower overall well cost for oil and gas operators. We believe we are currently a preferred contractor for operators in both U.S. and international locations, which we believe is a result of our reputation for providing efficient, safe, environmentally conscious and innovative drilling services, in addition to quality equipment, personnel, service and experience.
 
Contracts
 
Most drilling contracts are awarded based on competitive bidding. The rates specified in drilling contracts are generally on a dayrate basis, and vary depending upon the type of rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions and other variables. Our contracts generally provide for an operating dayrate during drilling operations, with lower rates for periods of equipment breakdown, customer stoppage, adverse weather or other conditions, and no payment when certain conditions continue beyond a contractually established duration. When a rig mobilizes to or demobilizes from an operating area, the contract typically provides for a different dayrate or specified fixed payments during the mobilization or demobilization. The terms of most of our contracts are based on either a specified period of time or the time required to drill a specified number of wells. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional time period, or by exercising a right of first refusal. Most of our contracts allow termination by the customer prior to the end of the term without penalty under certain circumstances, such as the loss of or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. Many of our contracts require the customer to pay an early termination fee if the customer terminates a contract before the end of the term without cause, but in the remainder of the contracts the customer has the discretion to terminate the contract without cause prior to the end of the term without penalty.


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Rental tools contracts are typically on a dayrate basis with rates based on type of equipment, investment and competition. Rental rates generally apply from the time the equipment leaves our facility until it is returned. Rental contracts generally require the customer to pay for lost, lost-in-hole or damaged equipment.
 
Seasonality
 
Our rigs in the GOM are subject to severe weather during certain periods of the year, particularly during hurricane season from June through November, which could halt operations for prolonged periods or limit contract opportunities during that period. In addition, mobilization and demobilization of rigs in arctic regions can be affected by seasonal changes in weather.
 
Insurance and Indemnification
 
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch throughs, craterings, fires, explosions, pollution, and damage or loss during transportation. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations.
 
Our drilling contracts provide for varying levels of indemnification between ourselves and our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of 12-month policy periods.
 
Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling contract, for liability due to control-of-well events, liability arising from named windstorms and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. Generally, our program provides liability coverage up to $200 million, with a retention of $1 million or less.
 
Control-of-well events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our program provides coverage for third-party liability claims relating to pollution from a control-of-well event up to $200 million per occurrence, with the first $10 million of such coverage also covering re-drilling of the well and control-of-well costs under a Contingent Operators Extra Expense policy. Our program also provides coverage for liability resulting from pollution events originating from our rigs up to $200 million per occurrence. We retain the risk for liability not indemnified by the customer below the retention and in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.
 
Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, including damage arising from a named windstorm in the U.S. Gulf of Mexico up to $20 million.
 
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases may require us to indemnify our customers. 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. However, in certain drilling contracts we assume liability for damage to our customer’s property and other third-party property on the rig resulting from our negligence, subject to negotiated caps per occurrence, and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law. In addition, our customers typically indemnify us for damage to our equipment down-hole, and in some cases our subsea equipment, generally based on replacement cost minus some level of depreciation.
 
Our customers typically assume responsibility for and indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages, arising from operations under the contract and originating below the surface of the land or water, including as a result of blow-outs or cratering of


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the well. In some drilling contracts, however, we may have liability for damages resulting from such pollution or contamination caused by our gross negligence, or, in some cases, ordinary negligence.
 
We generally indemnify the customer for legal and financial consequences of spills of industrial waste, lubricants, solvents and other contaminants (other than drilling fluid) on the surface of the land or water originating from our rigs or equipment. We typically require our customers to retain liability for spills of drilling fluid (sometimes called “mud”) which circulates down-hole to the drill bit, lubricates the bit and washes debris back to the surface. Drilling fluid often contains a mixture of synthetics, the exact composition of which is prescribed by the customer based on the particular geology of the well being drilled.
 
The above description of our insurance program and the indemnification provisions typically found in our drilling contracts is only a summary as of the date hereof 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
 
The following table sets forth the composition of our employee base:
 
                 
    December 31,  
    2010     2009  
 
International Drilling
    740       1,108  
Alaska(1)
    138       140  
U.S. Drilling
    329       347  
Rental Tools
    250       240  
Project Management and Engineering Services, Construction Contract and Corporate(2)
    554       537  
                 
Total employees
    2,011       2,372  
                 
 
 
(1) Our employees in Alaska are supporting the business expansion into this region.
 
(2) Includes 327 and 301 employees located in Russia who support the Orlan platform and Yastreb rig drilling activities in 2010 and 2009, respectively.
 
Environmental Considerations
 
Our operations are subject to numerous federal, state, local and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous foreign and domestic governmental agencies, such as the U.S. Environmental Protection Agency (EPA), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas; require remedial action to prevent pollution from former operations; and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the same markets. While our management believes that we comply with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.
 
As an owner or operator of both onshore and offshore facilities, including mobile offshore drilling rigs in or near waters of the United States, we may be liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of


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1990 (OPA), the Clean Water Act (CWA), the Clean Air Act (CAA), the Outer Continental Shelf Lands Act (OCSLA), the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the Resource Conservation and Recovery Act (RCRA), Emergency Planning and Community Right to Know Act (EPCRA), Hazardous Materials Transportation Act (HMTA) and comparable state laws, each as may be amended from time to time. In addition, we may also be subject to applicable state law and other civil claims arising out of any such incident.
 
The OPA and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” includes the owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability of oil removal costs and a variety of public and private damages to each responsible party.
 
The OPA liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place and functioning as an offshore facility. If operating as a vessel, liability limits of $600 per gross ton or $0.5 million, whichever is greater, apply. If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil on or above the water surface, with liability limits of $1,200 per gross ton or $10.0 million, whichever is greater. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actually incurred by a governmental entity for actual or threatened oil discharges associated with any Outer Continental Shelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.
 
Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility, for offshore facilities and vessels in excess of 300 gross tons (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels. The OPA requires owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal Outer Continental Shelf waters, with higher amounts, up to $150.0 million, in certain limited circumstances where the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. For “tank vessels,” as our offshore drilling rigs are typically classified, the OPA requires owners and operators to demonstrate financial responsibility in the amount of their largest vessel’s liability limit, as those limits are described in the preceding paragraph. A failure to comply with ongoing requirements or inadequate cooperation in a spill may even subject a responsible party to civil or criminal enforcement actions.
 
In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
 
All of our operating U.S. barge drilling rigs have zero-discharge capabilities as required by law, such as CWA. In addition, in recognition of environmental concerns regarding dredging of inland waters and permitting requirements, we conduct negligible dredging operations, with approximately two-thirds of our offshore drilling contracts involving directional drilling, which minimizes the need for dredging. However, the existence of such laws and regulations (e.g., Section 404 of the CWA, Section 10 of the Rivers and Harbors Act, etc.) has had and will continue to have a restrictive effect on us and our customers.
 
Our operations are also governed by laws and regulations related to workplace safety and worker health, primarily the Occupational Safety and Health Act and regulations promulgated thereunder. In addition, various


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other governmental and quasi-governmental agencies require us to obtain certain miscellaneous permits, licenses and certificates with respect to our operations. The kind of permits, licenses and certificates required in our operations depend upon a number of factors. We believe that we have all such miscellaneous permits, licenses and certificates that are material to the conduct of our existing business.
 
CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response and remediation costs, as well as natural resource damages. Few defenses exist to the liability imposed by CERCLA.
 
RCRA generally does not regulate most wastes generated by the exploration and production of oil and gas. 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, natural gas or geothermal energy.” However, these wastes may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to the warming of the atmosphere resulting in climate change. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, are attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.
 
In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. In the United States, federal legislation imposing restrictions on GHGs is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of GHGs and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions. In addition, the EPA is taking steps that would result in the regulation of GHGs as pollutants under the CAA. To-date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, effective December 29, 2009, which establishes a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010 which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Finally, on November 8, 2010, the EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to the EPA’s GHG reporting rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.
 
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws,


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regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and result in a disruption of our customers’ operations.
 
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
 
We operate in five segments:  International Drilling, U.S. Drilling, Rental Tools, Project Management and Engineering Services, and Construction Contract. Information about our reportable segments and operations by geographic areas for the years ended December 31, 2010, 2009 and 2008 is set forth in Note 10 in the notes to the consolidated financial statements included in Item 8 of this report.
 
EXECUTIVE OFFICERS
 
Officers are elected each year by the board of directors following the annual meeting for a term of one year and until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:
 
  •  Robert L. Parker Jr., 62, is the executive chairman of the board of directors. Mr. Parker joined the Company in 1973 as a contract representative, and was appointed manager of U.S. operations and a vice president later in 1973. He was elected executive vice president in 1976, and president and chief operating officer in 1977. In 1991, he was elected chief executive officer, was appointed chairman in 2006, and has retained the position of executive chairman since 2009. He has been a director since 1973.
 
  •  David C. Mannon, 53, is president, chief executive officer and member of the board of directors. Mr. Mannon joined the Company in 2004 as senior vice president and chief operating officer, and was elected president in 2007, and chief executive officer and director in 2009. From 2003 to 2004, Mr. Mannon held the positions of president and chief executive officer of Triton Engineering Services Company (Triton), a subsidiary of Noble Drilling. From 1988 to March 2003 he held various other positions with Triton. From 1980 through 1988, Mr. Mannon served Sedco-Forex, formerly Sedco, as a drilling engineer.
 
  •  W. Kirk Brassfield, 55, was elected senior vice president and chief financial officer in 2005. Mr. Brassfield joined the Company in 1998 as controller and principal accounting officer, and was appointed vice president, finance and accounting in 2004. From 1991 through 1998, Mr. Brassfield served in various positions, including subsidiary controller and director of financial planning of MAPCO Inc., a diversified energy company. From 1979 through 1991, Mr. Brassfield served at the public accounting firm KPMG.
 
  •  Jon-Al Duplantier, 43, joined the Company in 2009 as vice president and general counsel. From 1995 to 2009, Mr. Duplantier served in several legal and business roles at ConocoPhillips, including senior counsel – Exploration and Production, managing counsel – Indonesia, executive assistant – Exploration and Production, and counsel – Dubai. Prior to joining ConocoPhillips, he served as a patent attorney for DuPont from 1992 to 1995.
 
  •  Philip Agnew, 42, joined the Company in December 2010 as vice president of technical services. Mr. Agnew has more than 20 years’ experience in design, construction and project management. From 2003 to 2010, Mr. Agnew held the position of President at Aker MH, Inc., a business unit of Aker Solutions AS. From 1998 to 2003, Mr. Agnew served as Project Manager and then vice president – Project Development at Signal International (previously Friede Goldman Offshore; TDI-Halter LP; Texas Drydock, Inc.). Prior to his career at Signal International, Mr. Agnew served a variety of leadership roles at Schlumberger Sedco Forex International Resources, Interface Consulting International, Inc., and Brown & Root, Inc.
 
  •  Philip A. Schlom, 46, joined the Company in 2009 as principal accounting officer and corporate controller. From 2008 to 2009, he held the position of vice president and corporate controller for Shared Technologies


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  Inc. From 1997 to 2008, Mr. Schlom held several senior financial positions at Flowserve Corporation, a leading manufacturer of pumps, valves and seals for the energy sector. From 1988 through 1997, Mr. Schlom worked at the public accounting firm PricewaterhouseCoopers.
 
Other Parker Drilling Company Officers
 
  •  Denis J. Graham, 61, joined the Company in 2000 as vice president of engineering. Mr. Graham served in a variety of positions for Diamond Offshore Drilling Company from 1979 to 2000, including senior vice president of technical services immediately prior to joining the Company. Mr. Graham is a Registered Professional Engineer in the State of Texas.
 
  •  David W. Tucker, 55, treasurer, joined the Company in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of the Company’s wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer of the Company in 1999.
 
  •  J. Daniel Chapman, 40, joined the Company in 2009 as chief compliance officer and counsel. Prior to joining the Company, Mr. Chapman was employed by Baker Hughes from 2002 to 2009 where he served in several legal counsel positions including compliance counsel, international trade counsel, division counsel (drilling fluids), and global ethics and compliance director. Prior to 2002, Mr. Chapman was employed as a securities and mergers and acquisitions lawyer with the law firms of Freshfields (London) and King & Spalding (Atlanta and Houston).
 
Available Information
 
We make available free of charge on our website at www.parkerdrilling.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (SEC). We also provide paper or electronic copies of our reports free of charge upon request. Additionally, these reports are available on an Internet website maintained by the SEC at http://www.sec.gov.
 
ITEM 1A.   RISK FACTORS
 
The contract drilling, project management and engineering services, and rental tools and construction businesses involve a high degree of risk. You should consider carefully the risks and uncertainties described below and the other information included in this Form 10-K, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data, before deciding to invest in our securities. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of the following risks or uncertainties actually occurs, our business, financial condition or results of operations could be adversely affected.
 
Risks Related to Our Business
 
Volatile oil and natural gas prices impact demand for our drilling and related services. A decrease in demand for crude oil and natural gas or other factors may reduce demand for our services and substantially reduce our profitability or result in losses.
 
The success of our operations is significantly dependent upon the exploration and development activities of the major, independent and national oil and gas companies that comprise our customer base. Oil and natural gas prices and market expectations regarding potential changes in these prices can be extremely volatile, and therefore, the level of exploration and production activities can be extremely volatile. Increases or decreases in oil and natural gas prices and expectations of future prices could have an impact on our customers’ long-term exploration and development activities, which in turn could materially affect our business and financial performance. Higher commodity prices do not necessarily result in increased drilling activity because our customers’ expectations of future commodity prices typically drive demand for our drilling services.


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Commodity prices and demand for our drilling and related services also depends upon other factors, many of which are beyond our control, including:
 
  •  the demand for oil and natural gas;
 
  •  the cost of exploring for, producing and delivering oil and natural gas;
 
  •  expectations regarding future energy prices;
 
  •  advances in exploration, development and production technology;
 
  •  the adoption or repeal of laws and government regulations, both in the United States and other countries;
 
  •  the imposition or lifting of economic sanctions against foreign countries;
 
  •  the number of ongoing and recently completed rig construction projects which may create overcapacity;
 
  •  local and worldwide military, political and economic events, including events in the oil producing countries in Africa, the Middle East, Russia, Central Asia, Southeast Asia and Americas;
 
  •  the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels and prices;
 
  •  the level of production by non-OPEC countries;
 
  •  weather conditions;
 
  •  expansion or contraction of worldwide economic activity, which affects levels of consumer and industrial demand;
 
  •  the rate of discovery of new oil and natural gas reserves;
 
  •  domestic and foreign tax policies;
 
  •  acts of terrorism in the United States or elsewhere;
 
  •  the development and use of alternative energy sources; and
 
  •  the policies of various governments regarding exploration and development of their oil and natural gas reserves.
 
Our operations were impacted by the 2010 drilling rig accident in the U.S. Gulf of Mexico and its consequences and could be adversely affected in the future
 
On April 22, 2010, the Deepwater Horizon, a deepwater drilling rig owned by another contractor that was operating in the U.S. Gulf of Mexico, sank after an apparent blowout and fire (Macondo well blowout). In response to the incident, on May 30, 2010, the BOEMRE, of the U.S. Department of the Interior, at the time known as the Minerals Management Service implemented a moratorium on certain drilling activities in the U.S. Gulf of Mexico (GOM). On October 12, 2010, the BOEMRE announced that it was lifting the moratorium subject to certain specified conditions. During the pendency of the moratorium, the BOEMRE implemented various environmental, technological and safety measures intended to improve offshore safety systems and environmental protection. Among other things, each operator is required to conduct a specific review of its operations and to certify to the BOEMRE that it is in compliance with the new requirements and current regulations. Operators are also required to submit independent third-party reports on the design and operation of certain pieces of drilling equipment, including blowout preventers (BOPs) and other well control systems and to conduct tests on the functionality of various rig parts and to submit the results of those tests to the BOEMRE. Additional regulations address new standards for certain equipment involved in the construction of offshore wells, especially BOPs, and require operators to implement and enforce a safety and environmental management system including regular third-party audits of safety procedures and drilling equipment to insure that offshore rig personnel and equipment remain in compliance with the new regulations. With respect to operations that were subject to the moratorium, the reports and certifications are required to be provided to the BOEMRE prior to commencement of operations following expiration of the moratorium.


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As a consequence of the Macondo well blowout, the resulting moratorium, increased regulation and longer times to obtain required permits, offshore drilling operations in the GOM have been significantly reduced. Although we had no ongoing drilling operations directly subject to the now lifted moratorium, our Rental Tools segment has customers with operations that were negatively affected. In addition, some contract drillers and operators with floating rigs located in the region have chosen to relocate the units to other international drilling areas. We cannot currently predict the rate at which new well permits will be issued or the rate at which rigs will be allowed to return to work once compliance with the new regulations has been demonstrated. The process followed by the BOEMRE to review and approve well permit applications is likely to continue to be protracted relative to past experience, resulting in significant delays in the resumption of drilling in deepwater GOM that could persist through 2011. Significant continuing delay in the issuance of drilling permits or the resumption of operations, the possibility of additional regulations and government oversight and the possibility of increased legal liability could cause additional floating rigs to depart the U.S. GOM, with fewer customers operating in the region. If this were to occur, the market for our rental tools could be further adversely affected.
 
Continued effects of the economic recession may result in lower demand for our drilling rigs and rental tools business, which could have a material adverse effect on our drilling, project management and engineering services and rental tool business.
 
Continued effects of the economic recession or a further slowdown in economic activity could lead to uncertainty in corporate credit availability and capital market access and could reduce worldwide demand for energy and result in lower crude oil and natural gas prices. Our business depends to a significant extent on the level of international onshore drilling activity and GOM inland and offshore drilling activity for oil and natural gas. Depressed oil and gas prices will reduce the level of exploration, development and production activity which could cause our revenues and margins to decline, decrease daily rates and utilization of our rigs and limit our future growth prospects. Any significant decrease in daily rates or utilization of our rigs could materially reduce our revenue and profitability. In addition, current and potential customers who depend on financing for their drilling projects may be forced to curtail or delay projects and may also experience an inability to pay suppliers and service providers, including us. Likewise, continued effects of the economic recession also could impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. All of these factors could have a material adverse effect on our business and financial results.
 
Rig upgrade, refurbishment and construction projects are subject to risks and uncertainties, including delays and cost overruns, which could have an adverse impact on our results of operations and cash flows.
 
We regularly make significant expenditures in connection with upgrading and refurbishing our rig fleet. These activities include planned upgrades to maintain quality standards, routine maintenance and repairs, changes made at the request of customers, and changes made to comply with environmental or other regulations. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:
 
  •  shortages of equipment or skilled labor;
 
  •  unforeseen engineering problems;
 
  •  unanticipated change orders;
 
  •  work stoppages;
 
  •  adverse weather conditions;
 
  •  unexpectedly long delivery times for manufactured rig components;
 
  •  unanticipated repairs to correct defects in construction not covered by warranty;
 
  •  failure or delay of third-party equipment vendors or service providers;
 
  •  unforeseen increases in the cost of equipment, labor or raw materials, particularly steel;


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  •  disputes with customers, shipyards or suppliers;
 
  •  latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
 
  •  financial or other difficulties with current customers at shipyards and suppliers;
 
  •  loss of revenue associated with downtime to remedy malfunctioning equipment not covered by warranty;
 
  •  unanticipated cost increases;
 
  •  loss of revenue and payments of liquidated damages for downtime to perform repairs associated with defects, unanticipated equipment refurbishment and delays in commencement of operations; and
 
  •  inability to obtain the required permits or approvals, including import/export documentation.
 
Any one of the above risks could adversely affect our financial condition and results of operations. Delays in the delivery of rigs being constructed or undergoing upgrade, refurbishment or repair may, in many cases, delay commencement of a drilling contract resulting in a loss of revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses, if any. If one of these contracts is terminated, we may not be able to secure a replacement contract on as favorable terms, if at all. Additionally, capital expenditures for rig upgrade, refurbishment or construction projects could exceed our planned capital expenditures, impairing our ability to service our debt obligations.
 
Failure to retain skilled and experienced personnel could affect our operations.
 
We require highly skilled and experienced personnel to provide our customers with the highest quality technical services and support for our drilling operations. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience we require. Competition for skilled labor and other labor required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creating upward pressure on wages. In periods of high utilization, we have found it more difficult to find and retain qualified individuals. A shortage in the available labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Increases in our operating costs could adversely affect our business and financial results. Moreover, the shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality, safety and timeliness of our operations.
 
Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
 
As of December 31, 2010, we had:
 
  •  $460.9 million of long-term debt and $9.1 million of unamortized debt discount which is included in equity pursuant to applicable accounting standards for convertible debt instruments;
 
  •  $12.0 million of current portion of long-term debt;
 
  •  $31.5 million of operating lease commitments; and
 
  •  $16.3 million of standby letters of credit.
 
Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations. We have in the past, and may in the future, incur negative cash flows from one or more segments of our operating activities. Our future cash flows from operating activities will be influenced by the demand for our drilling services, the utilization of our rigs, the dayrates that we receive for our rigs, demand for our rental tools, general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control.


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If we are unable to service our debt obligations, we may have to take one or more of the following actions:
 
  •  delay spending on capital projects, including maintenance projects and the acquisition or construction of additional rigs, rental tools and other assets;
 
  •  sell equity securities, sell assets; or
 
  •  restructure or refinance our debt.
 
Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale. Our ability to generate sufficient cash flow from operating activities to pay the principal of and interest on our indebtedness is subject to certain market conditions and other factors which are beyond our control.
 
Increases in the level of our debt and restrictions in the covenants contained in the instruments governing our debt could have important consequences to you. For example, they could:
 
  •  result in a reduction of our credit rating, which would make it more difficult for us to obtain additional financing on acceptable terms;
 
  •  require us to dedicate a substantial portion of our cash flows from operating activities to the repayment of our debt and the interest associated with our debt;
 
  •  limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, and create liens on our properties;
 
  •  place us at a competitive disadvantage compared with our competitors that have relatively less debt; and
 
  •  make us more vulnerable to downturns in our business.
 
Our current operations and future growth may require significant additional capital, and the amount of our indebtedness could impair our ability to fund our capital requirements.
 
Our business requires substantial capital. Currently, we anticipate that our capital expenditures in 2011 will be approximately $160 to $175 million, including approximately $75 to $85 million for maintenance projects and investments in rental tool equipment. We may require additional capital in the event of significant departures from our current business plan or unanticipated expenses. Sources of funding for our future capital requirements may include any or all of the following:
 
  •  cash on hand;
 
  •  funds generated from our operations;
 
  •  public offerings or private placements of equity and debt securities;
 
  •  commercial bank loans;
 
  •  capital leases; and
 
  •  sales of assets.
 
Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the indentures governing the 9.125% Senior Notes and the 2.125% Convertible Senior Notes and the documentation governing our senior secured credit facility. Failure to obtain appropriate financing, should the need for it develop, could impair our ability to fund our capital expenditure requirements and meet our debt service requirements and could have an adverse effect on our business.


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Certain of our contracts are subject to cancellation or delay by our customers without penalty and with little or no notice.
 
Certain of our contracts are subject to cancellation by our customers without penalty and with relatively little or no notice. When drilling market conditions are depressed, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. Further, due to government actions, a customer may no longer be able to operate in, or it may not be economical to operate in, certain regions. As a result, customers may leverage their termination rights in an effort to renegotiate contract terms.
 
Our customers may also seek to terminate drilling contracts if we experience operational problems. If our equipment fails to function properly and cannot be repaired promptly, we will not be able to engage in drilling operations, and customers may have the right to terminate the drilling contracts. In our construction operations, if a rig is not timely delivered to a customer or does not pass acceptance testing, a customer may in certain circumstances have the right to terminate the contract. Even the payment of a termination fee may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. The cancellation or renegotiation of a number of our drilling contracts could materially reduce our revenue and profitability. In November 2010, BP suspended construction on the Liberty extended-reach drilling rig in Alaska, which is the sole project in our construction contract segment, and our construction contract has expired. In addition, our O&M contract with respect to the Liberty rig is scheduled to expire on June 1, 2011. BP has identified several areas of concern for which it has asked us to provide explanation and documentation, and we have done so. It is not possible to predict when or if BP will resume construction on the Liberty rig, or what additional actions it may request that we take with respect to the areas of concern it has raised. For more information about the status of the Liberty project, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
 
We rely on a small number of customers and the loss of a significant customer could adversely affect us.
 
A substantial percentage of our revenues are generated from a relatively small number of customers and the loss of a major customer could adversely affect us. In 2010, our two largest customers, BP and ExxonMobil (including subsidiaries and joint ventures) accounted for approximately 12.4 percent and 11.6 percent of our total revenues, respectively. Our revenues associated with BP are primarily for the construction of the BP-owned Liberty rig. Our revenues from ExxonMobil are primarily for drilling-related services. Our ten most significant customers collectively accounted for approximately 58.0 percent of our total revenues in 2010. Our results of operations could be adversely affected if any of our significant customers terminate their contracts with us, fail to renew our existing contracts or refuse to award new contracts to us.
 
The contract drilling and the rental tools businesses are highly competitive and cyclical, with intense price competition.
 
The contract drilling and rental tools markets are highly competitive and although we believe no single competitor is dominant, many of our competitors in both the contract drilling and rental tools business may possess greater financial resources than we do. Some of our competitors also are incorporated in countries that may provide them with significant tax advantages that are not available to us as a U.S. company and which may impair our ability to compete with them for many projects.
 
Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity, provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors have constructed numerous rigs during the previous period of high energy prices and, consequently, the number of rigs available in some of the markets in which we operate has exceeded the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. Historically, the drilling service industry has been highly cyclical, with periods of high demand, limited rig supply and high dayrates often followed by periods of low demand, excess rig supply and low dayrates. Periods of


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low demand and excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. During periods of decreased demand we typically experience significant reductions in dayrates and utilization. If we experience reductions in dayrates or if we cannot keep our rigs operating, our financial performance will be adversely impacted. Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our 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.
 
Our international operations are also subject to governmental regulation and other risks.
 
We derive a significant portion of our revenues from our international operations. In 2010, we derived approximately 45 percent of our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, among others:
 
  •  political, social and economic instability, war, terrorism and civil disturbances;
 
  •  limitations on insurance coverage, such as war risk coverage, in certain areas;
 
  •  expropriation, confiscatory taxation and nationalization of our assets;
 
  •  foreign laws and governmental regulation, including inconsistencies and unexpected changes in laws or regulatory requirements, and changes in interpretations or enforcement of existing laws or regulations;
 
  •  increases in governmental royalties;
 
  •  import-export quotas or trade barriers;
 
  •  hiring and retaining skilled and experienced workers, many of whom are represented by foreign labor unions;
 
  •  work stoppages;
 
  •  damage to our equipment or violence directed at our employees, including kidnapping;
 
  •  piracy of vessels transporting our people or equipment;
 
  •  unfavorable changes in foreign monetary and tax policies;
 
  •  solicitation by government officials for improper payments or other forms of corruption;
 
  •  foreign currency fluctuations and restrictions on currency repatriation;
 
  •  repudiation, nullification, modification or renegotiation of contracts; and
 
  •  other forms of governmental regulation and economic conditions that are beyond our control.
 
We currently have operations in 12 countries. Our operations are subject to interruption, suspension and possible expropriation due to terrorism, war, civil disturbances, political and capital instability and similar events, and we have previously suffered loss of revenue and damage to equipment due to political violence. Recent civil and political disturbances in Tunisia, Egypt, Libya and other North African countries may affect our operations. We currently have 2 rigs in Algeria. To the extent that Algeria experiences similar events, our operations in Algeria could be adversely affected. We may not be able to obtain insurance policies covering risks associated with these types of events, especially political violence coverage, and such policies may only be available with premiums that are not commercially justifiable.
 
Our international operations are subject to the laws and regulations of a number of foreign countries whose political, regulatory and judicial systems and regimes may differ significantly from those in the United States. Our ability to compete in international contract drilling markets may be adversely affected by foreign governmental regulations and/or policies that favor the awarding of contracts to contractors in which nationals of those foreign countries have substantial ownership interests or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions or fees from time to time on the transfer of funds to us.


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In addition, tax and other laws and regulations in some foreign countries are not always interpreted consistently among local, regional and national authorities, which often results in good faith disputes between us and governing authorities. The ultimate outcome of these disputes is never certain, and it is possible that the outcomes could have an adverse effect on our financial performance.
 
A portion of the workers we employ in our international operations are members of labor unions or otherwise subject to collective bargaining. We may not be able to hire and retain a sufficient number of skilled and experienced workers for wages and other benefits that we believe are commercially reasonable.
 
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against 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. Given the international scope of our operations, we are exposed to risks of currency fluctuation and restrictions on currency repatriation. We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts payable in U.S. dollars or freely convertible foreign currency. In addition, some parties with which we do business could require that all or a portion of our revenues be paid in local currencies. Foreign currency fluctuations therefore could have a material adverse effect upon our results of operations and financial condition.
 
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments may also impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.
 
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations can cause delays in shipments and unscheduled operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts, seizure of shipments and loss of import and export privileges.
 
We are subject to hazards customary for drilling operations, which could adversely affect our financial performance if we are not adequately indemnified or insured.
 
Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and natural gas well fires and explosions, natural disasters, pollution and mechanical failure. Our offshore operations also are subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. We have had accidents in the past demonstrating some of these hazards. To the extent that we are unable to insure against these risks or to obtain indemnification agreements to adequately protect us against liability from all of the consequences of the hazards and risks described above, then the occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not continue to be available to cover any or all of these risks. For example, pollution, reservoir damage and environmental risks generally are not fully insurable. Even if such insurance is available, insurance premiums or other costs may rise significantly in the future, so as to make the cost of such insurance prohibitive. For a description of our indemnification obligations and insurance, please read Item 1. “Business — Insurance and Indemnification.”
 
Certain areas in and near the GOM are subject to hurricanes and other extreme weather conditions. When operating in the GOM, our drilling rigs and rental tools may be located in areas that could cause them to be susceptible to damage or total loss by these storms. In addition, damage caused by high winds and turbulent seas to


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our rigs, our shore bases and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the effects of the damages can be repaired.
 
The oil and natural gas industry has sustained several catastrophic losses in recent years, including damage from hurricanes in the GOM. As a result, insurance underwriters have increased insurance premiums and restricted certain insurance coverage such as for losses arising from a named windstorm.
 
Although not a hazard specific to our drilling operations, we could incur significant liability in the event of loss or damage to proprietary data of operators or third parties during our transmission of this valuable data.
 
Government regulations and environmental risks, which reduce our business opportunities and increase our operating costs, might become more stringent in the future.
 
Government regulations control and often limit access to potential markets and impose extensive requirements concerning employee safety, environmental protection, pollution control and remediation of environmental contamination. Environmental regulations, in particular, prohibit access to some markets locations and make others less economical, increase equipment and personnel costs, and often impose liability without regard to negligence or fault. In addition, governmental regulations, such as those related to climate change, may discourage our customers’ activities, reducing demand for our products and services. We may be liable for damages resulting from pollution of offshore waters and, under United States regulations, must establish financial responsibility in order to drill offshore. See Part I, Business, “Environmental Considerations.”
 
Regulation of greenhouse gases and climate change could have a negative impact on our business.
 
Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.
 
In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on the countries that had ratified it. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. In the United States, federal legislation imposing restrictions on GHGs is under consideration. In addition, the EPA is taking steps that would result in the regulation of GHGs as pollutants under the Clean Air Act (the CAA). To date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, effective December 29, 2009, which establishes a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Finally, on November 8, 2010, the EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to the EPA’s GHG reporting rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.
 
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international


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agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations.
 
We are regularly involved in litigation, some of which may be material.
 
We are regularly involved in litigation, claims and disputes incidental to our business, which at times involve claims for significant monetary amounts, some of which would not be covered by insurance. We undertake all reasonable steps to defend ourselves in such lawsuits. Nevertheless, we cannot predict the ultimate outcome of such lawsuits and any resolution which is adverse to us could have a material adverse effect on our financial condition. See Note 11, “Commitments and Contingencies,” in Item 8 of this Form 10-K for a discussion of the material legal proceedings affecting us.
 
We are currently conducting an investigation into possible violations of the Foreign Corrupt Practices Act (FCPA) and other laws concerning our international operations. The Securities and Exchange Commission and the Department of Justice are conducting parallel investigations into possible FCPA violations. If we are found to have violated the FCPA or other legal requirements, we may be subject to criminal and civil penalties and other remedial measures, which could materially harm our business, results of operations, financial condition and liquidity.
 
As previously disclosed, we received requests from the United States Department of Justice (DOJ) in July 2007 and the United States Securities and Exchange Commission (“SEC”) in January 2008 relating to our utilization of the services of a customs agent. The DOJ and the SEC are conducting parallel investigations into possible violations of U.S. law by the Company, including the FCPA. In particular, the DOJ and the SEC are investigating our use of customs agents in certain countries in which we currently operate or formerly operated, including Kazakhstan and Nigeria. The Company is fully cooperating with the DOJ and SEC investigations and is conducting an internal investigation into potential customs and other issues in Kazakhstan and Nigeria. The internal investigation identified issues relating to potential non-compliance with applicable laws and regulations, including the FCPA with respect to operations in Kazakhstan and Nigeria. At this point, we are unable to predict the duration, scope or result of the DOJ or the SEC investigation or whether either agency will commence any legal action.
 
Further, in connection with our internal investigation, we also have learned that an individual who may be considered a foreign official under the FCPA owns in trust a substantial stake in a foreign subcontractor with whom we formerly conducted business through a joint venture relationship in Kazakhstan. The joint venture no longer does business with the foreign subcontractor.
 
The DOJ and the SEC have a broad range of civil and criminal sanctions under the FCPA and other laws and regulations, which they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. These authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed. Recent civil and criminal settlements have included multi-million dollar fines, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with the FCPA. In addition, corporations may have to end or modify existing business relationships. Any of these remedial measures, if applicable to us, could have a material adverse impact on our business, results of operations, financial condition and liquidity.


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We are subject to laws and regulations concerning our international operations, including export restrictions, U.S. economic sanctions and other activities that we conduct abroad. We have conducted an internal review concerning our compliance with these legal requirements and have voluntarily disclosed the results of our review to the U.S. government. If we are not in compliance with applicable legal requirements, we may be subject to civil or criminal penalties and other remedial measures, which could materially harm our business, results of operations, financial condition and liquidity.
 
We are subject to laws and regulations restricting our international operations, including activities involving restricted countries, organizations, entities and persons that have been identified as unlawful actors or that are subject to U.S. economic sanctions. Pursuant to an internal review, we have identified certain shipments of equipment and supplies that were routed through Iran as well as other activities, including drilling activities, which may have violated applicable U.S. laws and regulations. We have reviewed these shipments, transactions and drilling activities to determine whether the timing, nature and extent of such activities or other conduct may have given rise to violations of these laws and regulations, and we voluntarily disclosed the results of our review to the U.S. government. At this point, we are unable to predict whether the government will initiate an investigation or any proceedings against us, or the ultimate outcome that may result from our voluntary disclosure. If U.S. enforcement authorities determine that we were not in compliance with export restrictions, U.S. economic sanctions or other laws and regulations that apply to our international operations, we may be subject to civil or criminal penalties and other remedial measures, which could have an adverse impact on our business, results of operations, financial condition and liquidity.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the demand for rental tools.
 
Hydraulic fracturing is a process sometimes used in the completion of oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. The EPA recently initiated a study to investigate the potential adverse impacts that fracturing may have on water quality and public health. Legislation has also been introduced in the U.S. Congress and some states that would require the disclosure of chemicals used in the fracturing process. If enacted, the legislation could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for our rental tools.
 
Risks Related to Our Common Stock
 
The market price of our common stock has fluctuated significantly.
 
The market price of our common stock may continue to fluctuate in response to various factors and events, most of which are beyond our control, including the following:
 
  •  the other risk factors described in this Form 10-K, including changes in oil and natural gas prices;
 
  •  a shortfall in rig utilization, operating revenue or net income from that expected by securities analysts and investors;
 
  •  changes in securities analysts’ estimates of the financial performance of us or our competitors or the financial performance of companies in the oilfield service industry generally;
 
  •  changes in actual or market expectations with respect to the amounts of exploration and development spending by oil and gas companies;
 
  •  general conditions in the economy and in energy-related industries;
 
  •  general conditions in the securities markets;
 
  •  political instability, terrorism or war; and
 
  •  the outcome of pending and future legal proceedings, investigations, tax assessments and other claims.


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A hostile takeover of our company would be difficult.
 
Some of the provisions of our Restated Certificate of Incorporation and of the Delaware General Corporation Law may make it difficult for a hostile suitor to acquire control of our company and to replace our incumbent management. For example, our Restated Certificate of Incorporation provides for a staggered Board of Directors and permits the Board of Directors, without stockholder approval, to issue additional shares of common stock or a new series of preferred stock.
 
Risks Related to our Debt Securities
 
We may not be able to repurchase our 9.125% Senior Notes upon a change of control.
 
Upon the occurrence of specific change of control events affecting us, the holders of our 9.125% Senior Notes will have the right to require us to repurchase our notes at 101 percent of their principal amount, plus accrued and unpaid interest. Our ability to repurchase our notes upon such a change of control event would be limited by our access to funds at the time of the repurchase and the terms of our other debt agreements. Upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our senior secured credit facilities, our notes and other outstanding indebtedness. The source of funds for these repayments would be our available cash or cash generated from other sources. However, we may not have sufficient funds available upon a change of control to make any required repurchases of this outstanding indebtedness.
 
In addition, the change of control provisions in the indenture governing our 9.125% Senior Notes may not protect the holders of our notes from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a “Change of Control” under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change that constitutes a “Change of Control” as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a “Change of Control” as defined in the indenture, we will not be required to make an offer to repurchase the notes and the holders may be required to continue to hold their notes despite the event.
 
We may not have sufficient cash to repurchase the 2.125% Convertible Senior Notes at the option of the holder upon a fundamental change or to pay the cash payable upon a conversion.
 
Upon the occurrence of a fundamental change as defined in the indenture governing our 2.125% Convertible Senior Notes, subject to certain conditions, we will be required to make an offer to repurchase for cash all outstanding notes at 100 percent of their principal amount plus accrued and unpaid interest, including additional amounts, if any, up to but not including the date of repurchase. In addition, unless we elect to satisfy our conversion obligation entirely in shares of our common stock, upon a conversion, we will be required to make a cash payment of up to $1,000 for each $1,000 in principal amount of notes converted. However, we may not have enough available cash or be able to obtain financing at the time we are required to make repurchases of tendered notes or settlement of converted notes. Additionally, any credit facility in place at the time of a repurchase or conversion of the notes may also limit our ability to use borrowings under that credit facility to pay for a repurchase or conversion of the notes and may prohibit us from making any cash payments on the repurchase or conversion of the notes if a default or event of default has occurred under that facility without the consent of the lenders under that credit facility. Our failure to repurchase tendered notes at a time when the repurchase is required by the indenture or to pay any cash payable on a conversion of the notes would constitute a default under the indenture. A default under the indenture or the fundamental change itself could lead to a default under the other existing and future agreements governing our indebtedness. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the notes or make cash payments upon conversion thereof.


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The indenture for our 9.125% Senior Notes and our senior secured credit agreement impose significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.
 
The indenture governing our 9.125% Senior Notes and the agreement governing our senior secured credit facility impose significant operating and financial restrictions on us. These restrictions limit our ability to:
 
  •  make investments and other restricted payments, including dividends;
 
  •  incur additional indebtedness;
 
  •  create liens;
 
  •  engage in sale leaseback transactions;
 
  •  sell our assets or consolidate or merge with or into other companies; and
 
  •  engage in transactions with affiliates.
 
These limitations are subject to a number of important qualifications and exceptions. Our senior secured credit agreement also requires us to maintain ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. These covenants may adversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities. A breach of any of these covenants could result in a default with respect to the related indebtedness. If a default were to occur, the holders of our 9.125% Senior Notes and the lenders under our senior secured credit facility could elect to declare the indebtedness, together with accrued interest, immediately due and payable. If the repayment of the indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness.
 
DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This Form 10-K contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements contained in this Form 10-K, other than statements of historical facts, are forward-looking statements for purposes of these provisions, including any statements regarding:
 
  •  stability of prices and demand for oil and natural gas;
 
  •  levels of oil and natural gas exploration and production activities;
 
  •  demand for contract drilling and drilling-related services and demand for rental tools;
 
  •  our future operating results and profitability;
 
  •  our future rig utilization, dayrates and rental tools activity;
 
  •  entering into new, or extending existing, drilling contracts and our expectations concerning when our rigs will commence operations under such contracts;
 
  •  growth through acquisitions of companies or assets;
 
  •  construction or upgrades of rigs and expectations regarding when these rigs will commence operations;
 
  •  capital expenditures for acquisition of rigs, construction of new rigs or major upgrades to existing rigs;
 
  •  scheduled delivery of drilling rigs for operation in Alaska under the terms of our agreement with BP Exploration (Alaska) Inc.;
 
  •  entering into joint venture agreements;
 
  •  our future liquidity;
 
  •  availability and sources of funds to reduce our debt and expectations of when debt will be reduced;


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  •  the outcome of pending or future legal proceedings, investigations, tax assessments and other claims;
 
  •  the availability of insurance coverage for pending or future claims;
 
  •  the enforceability of contractual indemnification in relation to pending or future claims;
 
  •  compliance with covenants under our senior secured credit facility and indentures for our senior notes; and
 
  •  organic growth of our operations.
 
In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses made by our management in light of their experience and perception of historical trends, current conditions, expected future developments and other factors they believe are relevant. Although our management believes that their assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The following factors, as well as any other cautionary language included in this Form 10-K, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:
 
  •  worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business;
 
  •  our inability to access the credit markets;
 
  •  the U.S. economy and the demand for natural gas;
 
  •  worldwide demand for oil;
 
  •  fluctuations in the market prices of oil and natural gas;
 
  •  imposition of unanticipated trade restrictions;
 
  •  unanticipated operating hazards and uninsured risks;
 
  •  political instability, terrorism or war;
 
  •  governmental regulations, including changes in accounting rules or tax laws or ability to remit funds to the U.S., that adversely affect the cost of doing business;
 
  •  changes in the tax laws that would allow double taxation on foreign sourced income;
 
  •  the outcome of our investigation and the parallel investigations by the SEC and the Department of Justice into possible violations of U.S. law, including the Foreign Corrupt Practices Act;
 
  •  contemplated U.S. legislation on carbon emissions;
 
  •  potential new “employer” taxes on U.S. health care plans;
 
  •  adverse environmental events;
 
  •  adverse weather conditions;
 
  •  global health concerns;
 
  •  changes in the concentration of customer and supplier relationships;
 
  •  ability of our customers and suppliers to obtain financing for their operations;
 
  •  unexpected cost increases for new construction and upgrade and refurbishment projects;
 
  •  delays in obtaining components for capital projects and in ongoing operational maintenance and equipment certifications;
 
  •  shortages of skilled labor;


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  •  unanticipated cancellation of contracts by operators;
 
  •  breakdown of equipment;
 
  •  other operational problems including delays in start-up of operations;
 
  •  changes in competition;
 
  •  the effect of litigation and contingencies; and
 
  •  other similar factors , some of which are discussed in documents referred to or incorporated by reference into this Form 10-K and our other reports and filings with the SEC.
 
Each forward-looking statement speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 2.   PROPERTIES
 
We lease corporate headquarters office space in Houston, Texas. Additionally, we own and lease office space and operating facilities in various locations, primarily to the extent necessary for administrative and operational support functions.


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Land and Barge Rigs
 
The following table shows, as of December 31, 2010, the locations and drilling depth ratings of our rigs available for service:
 
                     
        Year entered
  Drilling
   
        into service/
  depth rating
   
Name
 
Type(2)
 
upgraded
  (in feet)  
Location
 
International
                   
Asia Pacific(1)
                   
Rig 231
  L   1981/1997     13,000     Indonesia
Rig 253
  L   1982/1996     15,000     Indonesia
Rig 188
  L   1979/2003     18,000     New Zealand
Rig 246
  L   1981/1998     18,000     New Zealand
Rig 226
  HH   1989/2010     18,000     Papua New Guinea
CIS/AME
                   
Rig 264
  L   2007     20,000     Algeria
Rig 265
  L   2007     20,000     Algeria
Rig 107
  L   1983/2009     15,000     Kazakhstan
Rig 216
  L   2001/2009     25,000     Kazakhstan
Rig 230
  L   1980/2003     18,000     Kazakhstan
Rig 236
  L   1978/2008     18,000     Kazakhstan
Rig 247
  L   1981/2008     18,000     Kazakhstan
Rig 249
  L   2000/2009     25,000     Kazakhstan
Rig 257
  B   1999/2010     30,000     Kazakhstan
Rig 258
  L   2001/2009     25,000     Kazakhstan
Rig 269
  L   2008     21,000     Kazakhstan
Americas
                   
Rig 268
  L   1978/2009     30,000     Colombia
Rig 271
  L   1982/2009     30,000     Colombia
Rig 53
  B   1978/2007     18,000     Mexico
Rig 121
  L   1980/2007     18,000     Mexico
Rig 122
  L   1980/2008     18,000     Mexico
Rig 165
  L   1978/2007     30,000     Mexico
Rig 221
  L   1982/2007     30,000     Mexico
Rig 256
  L   1978/2007     25,000     Mexico
Rig 266
  L   2008     20,000     Mexico
Rig 267
  L   2008     20,000     Mexico
 


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          Year entered
    Drilling
       
          into service/
    depth rating
       
Name
  Type(2)     upgraded     (in feet)     Location  
 
US Drilling
                               
U.S. Gulf of Mexico (GOM)
                               
Rig 8
    B       1978/2007       14,000       GOM  
Rig 20
    B       1981/2007       13,000       GOM  
Rig 21
    B       1979/2007       14,000       GOM  
Rig 12
    B       1979/2006       18,000       GOM  
Rig 15
    B       1978/2007       15,000       GOM  
Rig 50
    B       1981/2006       20,000       GOM  
Rig 51
    B       1981/2008       20,000       GOM  
Rig 54
    B       1980/2006       25,000       GOM  
Rig 55
    B       1981/2010       25,000       GOM  
Rig 56
    B       1979/2005       25,000       GOM  
Rig 72
    B       1982/2005       30,000       GOM  
Rig 76
    B       1977/2009       30,000       GOM  
Rig 77
    B       2006/2006       30,000       GOM  
Unassigned
                               
Rig 270
    L             21,000        
 
 
(1) Excludes three rigs classified for accounting purposes as assets held for sale as of December 31, 2010.
 
(2) Type is defined as: L — land rig; B — barge rig; HH — heli-hoist rig.

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The following table presents our utilization rates and rigs available for service for the years ended December 31, 2010 and 2009:
 
                 
    YTD
    December 31,
    2010   2009
 
U.S. Gulf of Mexico
U.S. Gulf of Mexico barge rigs
               
Rigs available for service(1)
    13.0       15.0  
Utilization rate of rigs available for service(2)
    63 %     35 %
International Land & Barge Rigs
Asia Pacific Region
               
Rigs available for service(1)(3)
    8.0       8.0  
Utilization rate of rigs available for service(2)
    37 %     47 %
Americas Region
               
Rigs available for service(1)
    10.0       10.0  
Utilization rate of rigs available for service(2)
    78 %     82 %
CIS/AME Region
               
Rigs available for service(1)
    11.0       12  
Utilization rate of rigs available for service(2)
    45 %     76 %
Unassigned
               
Rigs available for service(1)
    1.0       1.0  
Utilization rate of rigs available for service(2)
    0 %     0 %
Total International Land & Barge Rigs
               
Rigs available for service(1)
    30.0       31.0  
Utilization rate of rigs available for service(2)
    53 %     68 %
 
 
(1) The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable to other similarly titled measures of other companies.
 
(2) Rig utilization rates are based on a weighted average basis assuming 365 days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled measures of other companies.
 
(3) December 31, 2010 three rigs were removed from the marketable rig count and classified as assets held for sale.
 
ITEM 3.   LEGAL PROCEEDINGS
 
For information on Legal Proceedings, see Note 11, Commitments and Contingencies, in the notes to the consolidated financial statements included in Item 8 of this annual report on Form 10-K, which information is incorporated herein by reference.


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Parker Drilling Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” The following table sets forth the high and low sales prices per share of our common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:
 
                                 
    2010   2009
Quarter
  High   Low   High   Low
 
First
  $ 5.85     $ 4.55     $ 3.39     $ 1.28  
Second
    5.76       3.75       5.39       1.80  
Third
    4.44       3.43       5.89       3.43  
Fourth
    4.95       3.85       6.54       4.19  
 
Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholders of record. As of February 18, 2011, our common stock was held by 1,774 holders of record and we had an estimated 20,987 beneficial owners.
 
Restrictions contained in our existing credit agreement and the indenture for the 9.125% Senior Notes restrict the payment of dividends. We have no present intention to pay dividends on our common stock in the foreseeable future.
 
Issuer Purchases of Equity Securities
 
The Company currently has no active share repurchase programs. Periodically, the Company purchases shares on the open market to meet our employer matching requirements under our Defined Contribution Plan. Additionally when restricted stock awarded by the Company becomes taxable compensation to personnel, shares may be withheld to satisfy the associated withholding tax liabilities. Information on our purchases of equity securities by means of such share withholdings is provided in the table below:
 
                 
    Issuer Purchases of Equity Securities  
    Total Number
       
    of Shares
    Average Price
 
Period
  Purchased     Paid Per Share  
 
October 1-31, 2010
    51,230     $ 4.37  
November 1-30, 2010
    38,429     $ 4.02  
December 1-31, 2010
    44,354     $ 4.56  
                 
Total
    134,013     $ 4.33  
                 


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling Company for each of the five years in the period ended December 31, 2010. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in this Form 10-K.
 
                                         
    Year Ended December 31,  
    2010     2009(1)     2008(1)(2)     2007(1)     2006(3)  
    (Dollars in thousands, except per share amounts)  
 
Income Statement Data
                                       
Total revenues
  $ 659,475     $ 752,910     $ 829,842     $ 654,573     $ 586,435  
Total operating income
    45,107       39,322       59,180       190,983       143,326  
Equity in loss of unconsolidated joint venture, net of tax
                (1,105 )     (27,101 )      
Other expense
    (33,602 )     (29,495 )     (28,405 )     (24,141 )     (25,891 )
Income tax (expense) benefit
    (26,213 )     (560 )     (6,942 )     (36,895 )     (36,409 )
Net income (loss)
    (14,708 )     9,267       22,728       102,846       81,026  
Net income (loss) attributable to controlling interest
    (14,461 )     9,267       22,728       102,846       81,026  
Basic earnings per share:
                                       
Income from continuing operations
  $ (0.13 )   $ 0.08     $ 0.20     $ 0.94     $ 0.76  
Net income (loss) attributable to controlling interest
  $ (0.13 )   $ 0.08     $ 0.20     $ 0.94     $ 0.76  
Diluted earnings per share:
                                       
Income from continuing operations
  $ (0.13 )   $ 0.08     $ 0.20     $ 0.93     $ 0.75  
Net income (loss) attributable to controlling interest
  $ (0.13 )   $ 0.08     $ 0.20     $ 0.93     $ 0.75  
Balance Sheet Data
                                       
Cash and cash equivalents
  $ 51,431     $ 108,803     $ 172,298     $ 60,124     $ 92,203  
Marketable securities
                            62,920  
Property, plant and equipment, net
    816,147       716,798       675,548       585,888       435,473  
Assets held for sale
    5,287                         4,828  
Total assets
    1,274,555       1,243,086       1,205,720       1,067,173       901,301  
Total long-term debt including current portion of long-term debt
    472,862       423,831       441,394       349,309       329,368  
Total equity
    588,066       595,899       582,172       549,322       459,099  
 
 
(1) The Company adopted, effective January 1, 2009, newly issued accounting guidance regarding Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion which applies to all convertible debt instruments that have a “net settlement feature.” We reflected the impact of the new accounting guidance during each of the quarterly periods in our respective Quarterly Reports on Form 10-Q filed with the SEC during 2009. The adoption of this accounting guidance impacted the historical accounting for our $125 million aggregate principal amount of 2.125% Convertible Senior Notes due 2012 issued on July 5, 2007 by requiring adjustments to related interest expense, deferred income taxes, long-term debt, and shareholders’ equity for 2008 and 2007, which are illustrated in the notes to the consolidated financial statements.
 
(2) The 2008 results reflect a $100.3 million charge for impairment of goodwill that is described in the notes to the consolidated financial statements in Item 8 of this Form 10-K.
 
(3) The 2006 results reflect the reversal of a $12.6 million valuation allowance at the end of 2006 as it was no longer considered “more likely than not” under the accounting guidance related to accounting for income tax uncertainties and the utilization of $5.4 million of net operating losses, both related to Louisiana state net operating loss carryforwards.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
OVERVIEW AND OUTLOOK
 
Overview
 
Our results during the 2010 fourth quarter, and year, reflect our targeted geographic presence and complementary business mix that provide balance in what can be defined as a cyclical industry. Increases in revenues and earnings from our rental tools and barge drilling operations in the U.S. along with our project management business helped mitigate the effect of a slowdown in the utilization of our international rig fleet. We continue to make growth-oriented investments in our businesses, guided by our long-term strategy. In 2010, we had significant growth in our rental tools business. We continue to make strategic capital investments in this business and have expanded capabilities to service operators in several of the growing U.S. shale plays. We maintained a lead position in the U.S. barge drilling market based upon our performance, previous investment and upgrades to the barge fleet, as well as enhanced crew training. Despite the decline in E&P spending in some of our international drilling markets, we renewed and extended some existing contracts and obtained new contracts as customers turned to us to meet their drilling needs.
 
Our significant achievements of 2010 include:
 
  •  Rental Tools segment revenues increased 50 percent in 2010 compared to 2009, setting a new record. Rental Tools segment gross margins, excluding depreciation and amortization, increased 81 percent over 2009.
 
  •  Utilization in the Company’s U.S. Barge Drilling segment nearly doubled to 63 percent in 2010 from 35 percent in 2009.
 
  •  Over 50 percent of all wells drilled in 2010 by barge rigs in the shallow waters of the Gulf of Mexico were drilled by Parker rigs.
 
  •  In our International Drilling segment, the Americas region extended four contracts into 2012. We also secured three new contracts in our Asia Pacific region, one of which mobilized a rig that had been ready-stacked since 2009. In addition, the contract for Rig 257, the Company’s Caspian Sea arctic barge drilling rig, was extended into 2012.
 
  •  The Parker-operated Yastreb rig set a new, extended-reach drilling record of 40,502 feet, nearly eight miles, in total measured depth, operating incident-free throughout. This rig, designed, built and operated by us for Exxon Neftegas Limited, set this record during development drilling of the Sakhalin-1 Project’s Odoptu field.
 
Our recent performance and operating results during the 2010 fourth quarter have been driven by many of the same factors that have impacted our full year performance. Rental Tools segment revenues, segment gross margin and segment gross margin as a percent of revenues set new records. With facilities strategically located in key U.S. drilling markets and recent timely investments in rental tool inventory, our Rental Tools business continued to benefit from the continued growth in the development of shale formations and the expanded use of lateral drilling to exploit oil and natural gas resources. This led to increased demand, higher utilization and improved pricing. The increase in onshore demand was slightly offset by a decline in U.S. offshore and international revenues.
 
Our U.S. Drilling segment revenues, segment gross margin and segment gross margin as a percent of revenues increased, compared to the 2009 fourth quarter. Barge drilling in the shallow water and inland areas of the Gulf of Mexico remained active and we achieved improvements, year-to-year, in rigs working and dayrates.
 
International Drilling segment revenues, segment gross margin and segment gross margin as a percent of revenues all declined compared to the 2009 fourth quarter, primarily due to a reduction in drilling activity in the CIS/AME region and Mexico that resulted in a decline in rig utilization and lower revenues. This was offset in part by higher revenues from our Caspian Sea arctic barge rig which returned to a warm-stack rate during the fourth quarter of 2010, having been on a lower average dayrate in the prior year’s fourth quarter. Though operating costs were reduced as utilization declined, they were unable to keep pace with the decline in revenues.


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Project Management and Engineering Services segment revenues increased while segment gross margin and segment gross margin as a percent of revenues declined. The increase in revenues was primarily due to higher operating rates on the Yastreb rig and Orlan platform and increased engineering services revenues. The segment’s gross margin decline is primarily attributable to lower earnings on the 2010 fourth quarter’s engineering revenues compared with those of the prior year’s comparable period. Construction Contract revenues and earnings declined compared to the prior year’s fourth quarter, representative of the work completed during each period on the customer-owned Liberty rig.
 
Outlook
 
Growing demand and improving pricing in our U.S. markets for rental tools and barge drilling were sources of revenue and gross margin increases in 2010. Our project management business provided relatively steady results while international drilling activity experienced a decline in E&P spending in many of the markets we serve.
 
Looking ahead, we believe the rental tools business should continue to benefit from continued growth in U.S. drilling activity in the oil and liquid-rich shale plays. We expect to make further investments in this business which should contribute to our growth potential. We expect our Gulf of Mexico barge drilling business will continue to improve fleet utilization and will realize higher average dayrates in 2011. Low finding costs for oil and gas and an established and manageable regulatory environment should support continued interest among operators to drill in this market. International E&P spending is predicted by many industry forecasters to increase in 2011. Should this occur, we would expect it to impact our business later in the year. The portfolio of the Project Management and Engineering Services segment is expected to continue to generate steady revenues and earnings related to the current projects we are managing, with the addition of incremental revenues and earnings during the year from the Yastreb rig-move project.
 
Capital expenditures in 2011, funded primarily through operating cash flows and use of revolving credit facilities, are projected to be approximately $160 million to $175 million, including approximately $75 to $85 million for rig fleet maintenance projects and rental tool investments. Major project spending is expected to include construction and delivery of the two newbuild, Company-owned, drill rigs for Alaska.
 
RESULTS OF OPERATIONS
 
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
 
We recorded a net loss of $14.7 million for the year ended December 31, 2010, compared with net income of $9.3 million for the year ended December 31, 2009. Operating gross margin was $73.2 million for the year ended December 31, 2010, which was comprised of increases in gross margin from our Rental Tools and U.S. Drilling segments and decreases in gross margin from our International Drilling, Project Management and Engineering Services, and Construction Contract segments.


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The following is an analysis of our operating results for the comparable periods:
 
                                 
    Year Ended December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Revenues:
                               
International Drilling
  $ 220,371       33 %   $ 293,337       39 %
U.S. Drilling
    64,543       10 %     49,628       6 %
Rental Tools
    172,598       26 %     115,057       15 %
Project Management and Engineering Services
    110,873       17 %     109,445       15 %
Construction Contract
    91,090       14 %     185,443       25 %
                                 
Total revenues
  $ 659,475       100 %   $ 752,910       100 %
                                 
Operating gross margin:
                               
International drilling gross margin excluding depreciation and amortization
  $ 42,786       19 %   $ 101,851       35 %
U.S. drilling gross margin excluding depreciation and amortization
    11,209       17 %     1,574       3 %
Rental tools gross margin excluding depreciation and amortization
    112,562       65 %     62,317       54 %
Project management and engineering services gross margin excluding depreciation and amortization
    21,438       19 %     23,646       22 %
Construction contract gross margin excluding depreciation and amortization
    202       0 %     8,132       4 %
Depreciation and amortization
    (115,030 )             (113,975 )        
                                 
Total operating gross margin
    73,167               83,545          
General and administrative expense
    (30,728 )             (45,483 )        
Provision for reduction in carrying value of certain assets
    (1,952 )             (4,646 )        
Gain on disposition of assets, net
    4,620               5,906          
                                 
Total operating income
  $ 45,107             $ 39,322          
                                 
 
Segment gross margins, excluding depreciation and amortization, are computed as revenues less direct operating expenses, excluding depreciation and amortization expense; gross margin percentages are computed as segment gross margin, excluding depreciation and amortization, as a percentage of revenues. The segment gross margin amounts, excluding depreciation and amortization, and gross margin percentages should not be used as a substitute for those amounts reported under accounting principles generally accepted in the United States (GAAP). However, we monitor our business segments based on several criteria, including segment gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by a segment.


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Segment gross margin amounts are reconciled to our most comparable GAAP measure as follows:
 
                                         
                      Project
       
                      Management
       
    International
                & Engineering
    Construction
 
    Drilling     U.S. Drilling     Rental Tools     Services     Contract  
    (Dollars in thousands)  
 
Year Ended December 31, 2010
                                       
Operating gross margin(1)
  $ (11,511 )   $ (11,503 )   $ 74,541     $ 21,438     $ 202  
Depreciation and amortization
    54,297       22,712       38,021              
                                         
Operating gross margin excluding depreciation and amortization
  $ 42,786     $ 11,209     $ 112,562     $ 21,438     $ 202  
                                         
Year Ended December 31, 2009
                                       
Operating gross margin(1)
  $ 50,723     $ (26,797 )   $ 27,841     $ 23,646     $ 8,132  
Depreciation and amortization
    51,128       28,371       34,476              
                                         
Operating gross margin excluding depreciation and amortization
  $ 101,851     $ 1,574     $ 62,317     $  23,646     $   8,132  
                                         
 
 
(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.
 
International Drilling Segment
 
International Drilling segment revenues decreased $73.0 million to $220.4 million for the year ended December 31, 2010 as compared with December 31, 2009. The largest decline occurred in the CIS/AME region as a result of lower average fleet utilization for our operations throughout this region as spending on drilling programs continued to be adversely impacted by weaker financial conditions and reduced spending on state-involved E&P programs. In addition, our Caspian Sea Arctic barge, located in the CIS/AME region, was on reduced dayrates, including a zero dayrate for a period during 2010, as it underwent a planned refurbishment and upgrade project and a Parker-initiated repair program before ending the year on reduced day rates while our customer completed necessary permitting processes.
 
Revenues in our Americas region declined $15.6 million to $102.1 million primarily due to lower average fleet utilization and lower average dayrates in Mexico due to the completion of a contract in 2009 for Rig 53B and the release of two rigs in northern Mexico during 2010. Additionally, in the second quarter of 2009, we recognized a demobilization fee, which was not repeated in 2010. This was offset by increased revenues from our operations in Colombia, a result of growing activity in this market that led to higher utilization for our rigs.
 
In our Asia Pacific region, revenues decreased $7.5 million in 2010 to $26.4 million compared to 2009 due mainly to lower utilization of our rigs in New Zealand. This was partially offset by increased revenues in Indonesia and Papua New Guinea as we increased the number of rigs working and earned higher dayrates.
 
The International Drilling segment operating gross margin, excluding depreciation and amortization, decreased $59.1 million to $42.8 million during the year ended December 31, 2010 compared with the year ended December 31, 2009, with decreases in each of our three geographic regions. The largest decrease occurred in the CIS/AME region and is attributable to the overall lower revenues as well as increased expenses of the planned repair, refurbishment, and upgrade project for our Caspian Sea Arctic barge. The decrease in the Americas region is primarily due to the lower revenues and extended rig move costs and higher labor and fuel costs in Colombia. A decrease in the Asia Pacific region was due to lower overall revenues, a lower realized gross margin on the most recent contract award due to start-up costs, and the receipt in 2009 of a rig demobilization fee, not repeated in 2010.
 
U.S. Drilling Segment
 
U.S. Drilling segment revenues increased 30.1 percent, or $14.9 million, to $64.5 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The revenue increase was attributable to a


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recovering market, which has led to improved utilization for our barge drilling rig fleet. Utilization for our U.S. barge drilling rig fleet increased to 63 percent for 2010 from 35 percent for 2009 and was partially offset by a decline in average dayrates of approximately 17 percent due to a barge rig finishing a term contract at substantially higher rates to approximately $20,500 per day in 2010 from approximately $24,800 per day in 2009.
 
The U.S. Drilling segment operating gross margins, excluding depreciation and amortization, increased $9.6 million to $11.2 million for the year ended December 31, 2010 as compared to the same period of 2009 primarily as a result of the improved market and operating conditions and continued cost management.
 
Rental Tools Segment
 
Rental Tools segment revenues increased $57.5 million, or 50.0 percent to $172.6 million during the year ended December 31, 2010 as compared with 2009. The revenue increase is attributable to an increase in utilization resulting from improved market conditions, timely investments in rental tool inventory, and reduced customer discounting during the 2010 period compared with the same period during 2009. The expanded use of horizontal drilling to exploit both shale deposits and conventional oil and gas reservoirs and longer well-bores have led to greater market demand for rental tools. With its facilities strategically located in the major centers of drilling in the U.S., our Rental Tools business has benefited from servicing this growing demand. The increased revenues from domestic land markets was somewhat offset by a moderate decline in revenues to GOM offshore customers and the international offshore market in 2010 compared with 2009. The decline in revenues from GOM customers is due to the cessation and slow restart of drilling in that market following the Macondo well blowout in April 2010. The decline in international revenues for this segment was due to fewer placements of rental tools for offshore applications.
 
The rental tools segment operating gross margins, excluding depreciation and amortization, increased $50.2 million, or 80.6 percent to $112.6 million for 2010 as compared with 2009 as a result of the increase in revenues described above and reduced discounting in 2010 compared with 2009.
 
Project Management and Engineering Services Segment
 
Revenues for this segment increased $1.4 million during 2010 as compared with 2009. This increase was primarily the result of higher revenues related to our Arkutun Dagi project, increased revenues from our BP Liberty O&M contract and higher revenues in Orlan where we experienced higher dayrates offset by lower reimbursable revenues. The increases in revenue were offset by decreases in revenue for our operations on the Yastreb rig in Sakhalin Island and in Kuwait due to lower reimbursable revenues. For our Sakhalin operations, during 2009 we earned a fixed fee during the rig move, upgrade and customer modification phase of the contract, which was not repeated in 2010. Project Management and Engineering Services do not incur depreciation and amortization, and as such, gross margin for this segment decreased $2.2 million in 2010 compared with 2009 gross margin primarily due to increased operating expenses in Sakhalin.
 
Revenues from the construction contract segment decreased $94.4 million from $185.4 million for the year ended December 31, 2009 to $91.1 million for the year ended December 31, 2010. The Liberty rig project is accounted for on a percentage-of-completion basis with revenues and earnings recognized based on progress made relative to estimated total project costs. The decline in reported revenues reflects reduced work effort as the construction transitioned to rig-up labor from major construction in 2010. The construction contract segment does not incur depreciation and amortization, and as such, gross margin recognized during 2010 was $0.2 million compared with $8.1 million in 2009. The 2010 margin reduction is due to the increase in total estimated construction costs over a longer construction phase. For more information on the Liberty project, see Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
 
Other Financial Data
 
During 2010 we recorded a provision for reduction in carrying value of certain assets of $2.0 million related to disputed customer accounts receivable. Gains on asset dispositions were $4.6 million in 2010, a decrease of $1.3 million as a result of various asset sales in 2010 as compared with $5.9 million in 2009. The gain on asset


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dispositions in 2009 is primarily attributable to a $4.0 million settlement with a tugboat company in regards to a barge rig that was overturned in 2005. Interest expense for 2010 was $26.8 million, a decrease of $2.6 million as compared with 2009. The decrease in interest expense is primarily the result of a $7.5 million increase in 2010 in capitalized interest on major projects offset by a $4.9 million increase in 2010 in debt-related interest expense. Interest income for 2010 decreased $0.8 million to $0.3 million as compared with 2009. General and administration expense for 2010 decreased $14.8 million to $30.7 million as compared with 2009. The decrease in general and administrative costs is primarily related to lower legal fees in 2010 associated with the ongoing DOJ and SEC investigations and our work product related to various matters further discussed in Note 11, Commitments and Contingencies in the notes to the consolidated financial statements. In addition, we experienced lower employee insurance costs and travel related administrative costs resulting from lower overall company headcount. These decreases were slightly offset by an increase in professional fees related to consulting services.
 
Income tax expense was $26.2 million for the year ended December 31, 2010, as compared to income tax expense of $0.6 million for the year ended December 31, 2009. The increase in income tax expense for 2010 is primarily related to the unfavorable ruling by the Atyrau Oblast Court to uphold the lower court decision and allow the revised Tax Notification to stand as discussed in Note 11, Kazakhstan Ministry of Finance Tax Audit, in the notes to the consolidated financial statements. The Kazakhstan tax matter increased expense by approximately $14.5 million ($6.8 million, net of anticipated tax benefits), which includes approximately $6.5 million in tax, $4.8 million in interest and $3.2 million in penalties. The Company also adjusted reserves for tax uncertainties downward by $2.0 million for uncertainties where statute of limitations had expired, partially offset by increased reserves for potential disallowed costs related to currently disputed matters and unresolved matters in certain tax jurisdictions. In addition, tax expense increased from the Company’s settlement of a foreign tax audit for one of its subsidiaries for $1.2 million, which includes approximately $0.6 million of tax, $0.1 million of interest, and $0.5 million of penalties. Income tax expense for 2009 includes a benefit of an additional $5.4 million in addition to the $12.2 million claimed in 2008 for the recovery of prior years foreign taxes as a credit in the U.S. versus a deduction, the establishment of a valuation allowance of $0.5 million related to excess current year foreign tax credits and a charge of $1.8 million related to a characterization of certain intercompany notes for foreign tax credit calculation in accordance with accounting for tax uncertainties.
 
Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
 
We recorded net income of $9.3 million for the year ended December 31, 2009, as compared to net income of $22.7 million for the year ended December 31, 2008. Operating gross margin was $83.5 million for the year ended December 31, 2009, which consisted of decreases in U.S. Drilling and Rental Tools of $129.8 million offset by increases in international drilling operations, project management and engineering services and construction contract of $18.9 million and a $3.0 million decrease in depreciation expense as compared to the year ended December 31, 2008.


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The following is an analysis of our operating results for the comparable periods:
 
                                 
    Year Ended December 31,  
    2009     2008  
    (Dollars in thousands)  
 
Revenues:
                               
International drilling
  $ 293,337       39 %   $ 325,096       39 %
U.S. Drilling
    49,628       6 %     173,633       21 %
Rental Tools
    115,057       15 %     171,554       21 %
Project Management and Engineering Services
    109,445       15 %     110,147       13 %
Construction Contract
    185,443       25 %     49,412       6 %
                                 
Total revenues
  $ 752,910       100 %   $ 829,842       100 %
                                 
Operating gross margin:
                               
International drilling gross margin excluding depreciation and amortization
  $ 101,851       35 %   $ 93,687       29 %
U.S. drilling gross margin excluding depreciation and amortization
    1,574       3 %     89,202       51 %
Rental tools gross margin excluding depreciation and amortization
    62,317       54 %     104,506       61 %
Project management and engineering services gross margin excluding depreciation and amortization
    23,646       22 %     18,470       17 %
Construction contract gross margin excluding depreciation and amortization
    8,132       4 %     2,597       5 %
Depreciation and amortization
    (113,975 )             (116,956 )        
                                 
Total operating gross margin
    83,545               191,506          
General and administrative expense
    (45,483 )             (34,708 )        
Impairment of goodwill
                  (100,315 )        
Provision for reduction in carrying value of certain assets
    (4,646 )                      
Gain on disposition of assets, net
    5,906               2,697          
                                 
Total operating income
  $ 39,322             $ 59,180          
                                 
 
Segment gross margins, excluding depreciation and amortization, are computed as revenues less direct operating expenses, excluding depreciation and amortization expense; gross margin percentages are computed as segment gross margin, excluding depreciation and amortization, as a percentage of revenues. The segment gross margin amounts, excluding depreciation and amortization, and gross margin percentages should not be used as a substitute for those amounts reported under accounting principles generally accepted in the United States (GAAP). However, we monitor our business segments based on several criteria, including segment gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by a segment.


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Segment gross margin amounts are reconciled to our most comparable GAAP measure as follows:
 
                                         
                      Project
       
                      Management
       
    International
                & Engineering
    Construction
 
    Drilling     U.S. Drilling     Rental Tools     Services     Contract  
    (Dollars in thousands)  
 
Year Ended December 31, 2009
                                       
Operating gross margin(1)
  $ 50,723     $ (26,797 )   $ 27,841     $ 23,646     $ 8,132  
Depreciation and amortization
    51,128       28,371       34,476              
                                         
Operating gross margin excluding depreciation and amortization
  $ 101,851     $ 1,574     $ 62,317     $ 23,646     $ 8,132  
                                         
Year Ended December 31, 2008
                                       
Operating gross margin(1)
  $ 41,786     $ 53,964     $ 74,689     $ 18,470     $ 2,597  
Depreciation and amortization
    51,901       35,238       29,817              
                                         
Operating gross margin excluding depreciation and amortization
  $ 93,687     $ 89,202     $ 104,506     $  18,470     $   2,597  
                                         
 
 
(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.
 
International Drilling Segment
 
International Drilling segment revenues decreased $31.8 million to $293.3 million for the year ended December 31, 2009 as compared with December 31, 2008. Revenues in the CIS/AME region decreased by $10.3 million primarily attributable to a reduction in operating days for rigs operating on land in Kazakhstan and minimal drilling operations in Turkmenistan. These reductions in revenue were partially offset by increases in drilling revenue from operations in the Karachaganak area of Kazakhstan, Caspian Sea barge rig and Algeria, which increased by $4.5 million, $5.3 million and $1.9 million, respectively.
 
In our Americas region, revenues decreased $4.9 million due to lower revenues of $8.5 million in Mexico, due to contract completion on Rig 53B and lower average dayrates, offset by increased revenues of $3.6 million in Colombia, a result of higher utilization.
 
In our Asia Pacific region, revenues decreased $19.8 million due mainly to lower utilization in Papua New Guinea, Indonesia and New Zealand, whose revenues decreased by $14.9 million, $3.5 million and $1.4 million, respectively.
 
The International Drilling segment operating gross margin, excluding depreciation and amortization, increased $8.2 million to $101.9 million during the year ended December 31, 2009 compared to the year ended December 31, 2008, due primarily to increases in operating gross margin, excluding depreciation and amortization in the CIS/AME region and Colombia of $15.0 million and $1.2 million, respectively. The increases were partially offset by a decrease in Mexico of $8.0 million. The increase in the CIS/AME region is attributable to an overall increase in average dayrates and a decrease in operating expenses for reduced labor costs and fewer rigs in operation. The increase in Colombia is attributable to increased operating days. In Algeria, revenues increased due to decreased downtime and operating expenses were lower due to a reduction in labor related costs. The decrease in Mexico is attributable to reduced operating days as a result of the completion of the contract for Rig 53B.
 
U.S. Drilling Segment
 
Revenues from the U.S. Drilling segment decreased $124.0 million to $49.6 million for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The revenue reduction was primarily attributable to the decline in industry-wide barge drilling. As a result, we experienced a $28.7 million decrease for our barge drilling operations as average dayrates fell approximately $15,000 per day. Revenues were further


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decreased by $93.1 million as a result of rig fleet average utilization decreasing from 77 percent in 2008 to 35 percent in 2009 and $2.2 million in other decreases for reimbursable revenues.
 
As a result of the above mentioned factors, gross margins, excluding depreciation and amortization, decreased $87.6 million to $1.6 million for the year ended December 31, 2009 as compared to the same period of 2008.
 
Rental Tools Segment
 
Revenues from the Rental Tools segment decreased $56.5 million to $115.1 million during the year ended December 31, 2009 as compared to 2008. The decrease was due to greater discounting and lower utilization that was partially offset by decreased operating costs related to lower labor costs. The Rental Tools segment gross margins, excluding depreciation and amortization, decreased $42.2 million to $62.3 million for 2009 as compared with 2008.
 
Project Management and Engineering Services Segment
 
Revenues for this segment decreased $0.7 million during 2009 as compared with 2008. This slight decrease was attributable to lower revenues of $10.9 million in Orlan, where we were on a warm-stack, or reduced stand-by rate most of the year, $6.4 million in Kuwait due to lower reimbursable revenues related to the rigs under our management contract in Kuwait, and the completion of the management contract in China in 2009. These decreases were partially offset by $5.1 million of higher revenues for our operations on the Yastreb rig in Sakhalin Island and $18.1 million of higher revenues for engineering services primarily related to our Arkutun Dagi project. For Sakhalin operations, $0.2 million was due to higher dayrates and $4.9 million due to reimbursable expenses earned during the rig modification, upgrade and move phase of the contract. Project management and engineering services do not incur depreciation and amortization, and as such, gross margin for this segment increased $4.9 million in 2009 as compared to 2008 primarily due to the addition of revenues associated with the Arkutun Dagi project.
 
Construction Contract Segment
 
Revenues from the construction contract segment increased $136.0 million for the year ended December 31, 2009 compared with the year ended December 31, 2008.
 
Revenues from the construction of the extended-reach drilling rig for use in the Alaskan Beaufort Sea were $185.4 million for 2009 compared with $49.4 million in 2008. This project is a cost plus fixed fee contract. Gross margin for this EPCI project is based on the percentage of completion of the contract in which costs-to-date compared to projected total costs are used to determine the percentage of completion utilizing the cost to cost method. Gross margin recognized during 2009 was $8.1 million compared with $2.6 million in 2008.
 
Other Financial Data
 
Gains on asset dispositions were $5.9 million in 2009, an increase of $3.2 million as a result of various asset sales in 2009 as compared with $2.7 million in 2008. The gain on asset dispositions in 2009 is primarily attributable to a $4.0 million settlement with a tugboat company in regards to a barge rig that was overturned in 2005. Interest expense for 2009 was $29.5 million, an increase of $0.2 million as compared with 2008. Interest income for 2009 decreased $0.4 million as compared with 2008. General and administration expense for 2009 increased $10.8 million as compared with 2008. The increased general and administrative costs were primarily related to higher legal and professional fees associated with the ongoing DOJ and SEC investigations and our work product related to various matters further discussed in Note 11 in the notes to the consolidated financial statements. These fees included improvements to our overall compliance process, code of conduct and other matters arising as a result of our internal investigation and responses to the SEC and DOJ inquiries. In addition, we incurred severance and personnel-related costs of approximately $1.6 million in 2009.
 
Income tax expense was $0.6 million for the year ended December 31, 2009, as compared to income tax expense of $6.9 million for the year ended December 31, 2008. Income tax expense for 2009 includes a benefit of an additional $5.4 million to the amount of $12.2 million claimed in 2008 for the recovery of prior years foreign taxes as a credit in the U.S. versus a deduction, the establishment of a valuation allowance of $0.5 million related to excess current year foreign tax credits and a charge of $1.8 million accounted for under FIN 48 related to a characterization


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of certain intercompany notes for foreign tax credit calculation. Income tax expense for 2008 includes a benefit of $13.4 million of FIN 48 interest and foreign currency exchange rate fluctuations related to our settlement of interest related to our Kazakhstan tax case (see Note 11 in the notes to the consolidated financial statements), the establishment of a valuation allowance of $4.1 million related to a Papua New Guinea deferred tax asset, the reversal of a $5.7 million valuation allowance relating to 2007 foreign tax credits, a charge of $4.5 million accounted for under FIN 48 related to certain intercompany transactions between our U.S. companies and foreign affiliates, a charge of $12.6 million related to non-deductible goodwill and a benefit of $12.2 million for the recovering of prior years’ foreign taxes as a credit in the U.S. versus a deduction. Based on the level of projected future taxable income over the periods for which the deferred tax asset is deductible in Papua New Guinea, management believes that it is more likely than not that our subsidiary will not realize the benefit of this deduction in Papua New Guinea.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Liquidity
 
As of December 31, 2010, we had cash and cash equivalents of $51.4 million, a decrease of $57.4 million from December 31, 2009. The following table provides a summary for the last three years:
 
                         
    2010   2009   2008
    (Dollars in thousands)
 
Operating Activities
  $ 123,550     $ 110,872     $ 220,318  
Investing activities
    (212,709 )     (150,718 )     (196,607 )
Financing activities
    31,787       (23,649 )     88,463  
                         
Net change in cash and cash equivalents
    (57,372 )     (63,495 )     112,174  
 
Operating Activities
 
Cash flows from operating activities were $123.6 million in 2010, compared with $110.9 million in 2009. Before changes in operating assets and liabilities, cash was provided by operations primarily through a net loss of $14.7 million plus non-cash charges of $133.1 million. Net changes in operating assets and liabilities provided $5.2 million of cash in 2010, compared to $7.9 million used in 2009.
 
Cash flows from operating activities were $110.9 million in 2009, compared to $220.3 million in 2008. The net cash impact of earnings, after adjusting for the write-off of goodwill in 2008, was a reduction of $113.8 million in 2009. Working capital requirements decreased by $34.0 million in 2009, principally driven by a smaller increase in accounts receivable, a decrease in other current assets, an increase in accounts payable and accrued liabilities and higher accrued income taxes.
 
Investing Activities
 
Cash flows used in investing activities were $212.7 million for 2010. Our primary use of cash was $219.2 million for capital expenditures. Major capital expenditures for the period included $112.5 million for the construction of two new Alaska rigs and $48.9 million for tubular and other rental tools for Quail Tools. Sources of cash included $6.5 million of proceeds from asset sales.
 
Cash flows used in investing activities were $150.7 million for 2009. Our primary use of cash was $160.1 million for capital expenditures. Major capital expenditures for the period included $62.2 million for the construction of two new Alaska rigs and $36.8 million for tubular and other rental tools for Quail Tools. Sources of cash included $9.3 million of proceeds from asset sales.
 
Capital expenditures for 2011 are estimated to be $160 to $175 million and will primarily be directed to our Rental Tools inventory, completion of our two new Alaska rigs and normal levels of maintenance capital. Any discretionary spending will be evaluated based upon adequate return requirements and available liquidity. We believe that from our operating cash flows and borrowings under our revolving credit facilities, as required, we have sufficient cash and available liquidity to sustain operations and fund our capital expenditures for 2011, though there


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can be no assurance that we will continue to generate cash flows at sufficient levels or be able to obtain additional financing if necessary. See “Item 1A. Risk Factors” for a discussion of additional risks related to our business.
 
Financing Activities
 
Cash flows provided by financing activities were $31.8 million for 2010. Our primary financing activities included proceeds from the issuance of $300.0 million aggregate principal amount of 9.125% Notes, less $8.0 million of associated debt issuance costs, offset by the repayment of $225.0 million aggregate principal value of 9.625% Senior Notes including payment of $7.5 million of related debt extinguishment cost. In addition, we had a net pay down on our credit facilities of $29.0 million.
 
Cash flows used in financing activities were $23.6 million for 2009. Our primary uses of cash included a net pay down on our credit facilities of $22.0 million and excess tax benefits from stock options exercised of $1.8 million.
 
9.125% Senior Notes
 
On March 22, 2010, the Company issued $300,000,000 aggregate principal amount of 9.125% Senior Notes due 2018 (9.125% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A. (Trustee). The 9.125% Notes were issued at par with interest payable on April 1 and October 1 of each year, beginning October 1, 2010. Net proceeds from the 9.125% Notes offering were used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013, to repay $42.0 million of borrowings under the revolving credit facility and for general corporate purposes.
 
The 9.125% Notes are general unsecured obligations of the Company. The 9.125% Notes rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 9.125% Notes are jointly and severally guaranteed by substantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenue primarily outside the United States.
 
At any time prior to April 1, 2013, we may redeem up to 35 percent of the aggregate principal amount of 9.125% Notes at a redemption price of 109.125 percent of the principal amount, plus accrued and unpaid interest to the redemption date with the net cash proceeds of certain equity offerings by us. On and after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of 104.563% of principal amount, and at redemption prices decreasing each year thereafter to par. If we experience certain changes in control, we must offer to repurchase the 9.125% Notes at 101 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
 
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets; (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness; (iii) make investments; (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries; (viii) merge or consolidate with other entities; (ix) enter into transactions with affiliates; and (x) engage in certain business activities. Additionally, the indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
 
On June 21, 2010 pursuant to the Registration Rights Agreement among the Company, the guarantors named therein, the initial purchasers of the 9.125% Notes and the Trustee, entered into as of March 22, 2010 in connection with the closing of the 9.125% Notes offering, we filed an exchange offer registration statement with respect to an offer to exchange the 9.125% Notes for substantially identical notes that are registered under the Securities Act. The registration statement was deemed effective by the United States Securities and Exchange Commission (SEC) on September 1, 2010.
 
9.625% Senior Notes, due October 2013
 
As of December 31, 2009, we had outstanding $225.0 million in aggregate principal amount of 9.625% senior notes due 2013 (9.625% Notes). On March 8, 2010, we commenced a cash tender offer and consent solicitation for all of our outstanding 9.625% Notes, which expired on April 2, 2010 (Tender Offer). On March 22, 2010, we


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voluntarily called for redemption all of our 9.625% Notes that were not tendered pursuant to the Tender Offer, at the redemption price of 103.208% of the principal amount of the 9.625% Notes, or $1,032.08 per $1,000 principal amount of the 9.625% Notes. On April 21, 2010, we redeemed in full the remaining $128.7 million principal amount of 9.625% Notes. This redemption resulted in the Company recording debt extinguishment costs of $7.2 million during 2010.
 
2008 Credit Agreement:
 
On May 15, 2008, we entered into a credit agreement (Credit Agreement) consisting of a senior secured $80 million revolving credit facility (Revolver) and senior secured term loan facility (Term Loan) of up to $50 million. The Credit Agreement provides that subject to certain conditions, including the approval of the Administrative Agent and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan Facility or Revolving Credit Facility can be increased by an additional $50 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180 million. If the facility is increased, all other terms of the Credit Agreement remain the same, including covenants and Applicable Rates. The Credit Agreement terminates on May 14, 2013.
 
Revolver — The revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. The Applicable Rate varies from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75 percent to 2.25 percent for Base Rate loans, determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Revolving loans are available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were $25.0 million and $42.0 million in revolving loans outstanding at December 31, 2010 and December 31, 2009, respectively. Letters of credit outstanding as of December 31, 2010 and December 31, 2009 totaled $16.3 million and $12.7 million, respectively.
 
Term Loan — the Term Loan originated at $50.0 million and requires quarterly principal payments of $3.0 million. Interest on the Term Loan accrues at either a Base Rate plus 2.25 percent or LIBOR plus 3.25 percent. The outstanding balances on the Term Loan at December 31, 2010 and December 31, 2009 were $32.0 million and $44.0 million, respectively.
 
Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, each of which has executed guaranty agreements. The Credit Agreement contains certain customary affirmative and negative covenants. Our most restrictive of these covenants requires we maintain a consolidated leverage ratio of less than 4.00 to 1. The consolidated leverage ratio is based on the ratio of consolidated total debt to consolidated EBITDA as defined in the Credit Agreement. EBITDA, while not a GAAP measure, reflects a measurement of cash flow and is calculated as income before income taxes plus interest, income taxes, and depreciation and amortization. As of December 31, 2010 we are in compliance with all of our covenants. We do not currently anticipate triggering any of these covenants during 2011.
 
On January 15, 2010, the Credit Agreement was amended in anticipation of the issuance of 9.125% Notes described above, in order to, among other things, release certain subsidiaries from their obligations under the Credit Agreement, effective upon the repurchase or redemption of all the outstanding 9.625% Notes. These released subsidiaries are the Company’s immaterial subsidiaries and subsidiaries generating revenue primarily outside the United States. Upon the effectiveness of the amendment to the Credit Agreement, the guarantors under the Credit Agreement were the same as the guarantors of the 9.125% Notes.
 
2.125% Convertible Senior Notes
 
On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Convertible Senior Notes (the Notes) due July 15, 2012. The Notes were issued at par and interest is payable semiannually on July 15th and January 15th.


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The significant terms of the convertible notes are as follows:
 
  •  Notes Conversion Feature — The initial conversion price for Note holders to convert their notes into shares is at a common stock share price equivalent of $13.85 (77.2217 shares of common) stock per $1,000 note value. Conversion rate adjustments occur for any issuances of stock, warrants, rights or options (except for stock purchase plans or dividend re-investments) or any other transfer of benefit to substantially all stockholders, or as a result of a tender or exchange offer. The Company may, under advice of our Board of Directors, increase the conversion rate at our sole discretion for a period of at least 20 days.
 
  •  Notes Settlement Feature — Upon tender of the Notes for conversion, we can either settle entirely in shares of common stock or a combination of cash and shares of common stock, solely at our option. Our intent is to satisfy conversion obligation for our Notes in cash, rather than in common stock, for at least the aggregate principal amount of the Notes. This reduces the resulting potential earnings dilution to only include any possible conversion premium, which would be the difference between the average price of our shares and the conversion price per share of common stock.
 
  •  Contingent Conversion Feature — Note holders may only convert Notes when either sales price or trading price conditions are met, on or after the Notes’ due date or upon certain accounting changes or certain corporate transactions (fundamental changes) involving stock distributions. Make-whole provisions are only included in the accounting and fundamental change conversions such that holders do not lose value as a result of the changes.
 
  •  Settlement Feature — Upon conversion, we will pay either cash or provide shares of our common stock, if any, based on a daily conversion rate multiplied by a volume weighted average price of our common stock during a specified period following the conversion date. Conversions can be settled in cash or shares, solely at our discretion.
 
As of December 31, 2010, none of the conditions allowing holders of the Notes to convert had been met.
 
Concurrently with the issuance of the 2.125% Notes, we purchased a convertible note hedge (note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the 2.125% Notes. The note hedge included purchasing free-standing call options and selling free-standing warrants, both exercisable in our common shares. The note hedge allows us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the 2.125% Notes upon conversion.
 
The terms of the call options mirror the 2.125% Notes’ major terms whereby the call option strike price is the same as the initial conversion price as are the number of shares callable, $13.85 per share and 9,027,713 shares, respectively. This feature prevents dilution of our outstanding shares. The warrants allow us to sell 9,027,713 common shares at a strike price of $18.29 per share. The conversion price of the 2.125% Notes remains at $13.85 per share, and the existence of the call options and warrants serve to guard against dilution at share prices less than $18.29 per share, since we would be able to satisfy our obligations and deliver shares upon conversion of the 2.125% Notes with shares that are obtained by exercising the call options.
 
We paid a premium of approximately $31.48 million for the call options, and received proceeds for a premium of approximately $20.25 million for the sale of the warrants. This reduced the net cost of the note hedge to $11.23 million. The expiration date of the note hedge is the earlier of the last day on which the 2.125% Notes remain outstanding and the maturity date of the 2.125% Notes.
 
The 2.125% Notes are classified as a liability in our consolidated financial statements. Because we have the choice of settling the call options and the warrants in cash or shares of our common stock and these contracts meet all of the applicable criteria for equity classification, the cost of the call options and proceeds from the sale of the warrants are classified in stockholders’ equity in the Consolidated Balance Sheet. In addition, because both of these contracts are classified in stockholders’ equity and are solely indexed to our own common stock, they are not accounted for as derivatives.
 
Debt issuance costs related to the 2.125% Notes totaled approximately $3.6 million and are being amortized over the five year term of the 2.125% Notes using the effective interest method. Proceeds from the transaction of


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$110.2 million were used to redeem our outstanding senior floating rate notes, to pay the net cost of hedge and warrant transactions, and for general corporate purposes.
 
Other Liquidity
 
Our principal amount of long-term debt, including current portion, was $472.9 million as of December 31, 2010, which consists of:
 
  •  $125.0 million aggregate principal amount of 2.125% Convertible Senior Notes due July 15, 2012, less an associated $9.1 million in unamortized debt discount which is included in equity pursuant to applicable accounting standards for convertible debt instruments;
 
  •  $300.0 million aggregate principal amount of 9.125% Senior Notes, due April 1, 2018; and
 
  •  $57.0 million drawn against our 2008 Credit Facility, including $25.0 million under our Revolving Credit Facility and $32.0 million under our Term Loan Facility, $12.0 million of which is classified as current.
 
As of December 31, 2010, we had approximately $90.1 million of liquidity, which consisted of $51.4 million of cash and cash equivalents on hand and $38.7 million of availability under the 2008 Credit Facility. We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. We have no energy, commodity, foreign currency or interest rate derivative contracts at December 31, 2010.
 
The following table summarizes our future contractual cash obligations as of December 31, 2010:
 
                                         
          Less Than
    Years
    Years
    More Than
 
    Total     1 Year     2 - 3     4 - 5     5 Years  
    (Dollars in Thousands)  
 
Contractual cash obligations:
                                       
Long-term debt — principal(1)
  $ 482,000     $ 12,000     $ 170,000     $     $ 300,000  
Long-term debt — interest(1)
    207,303       32,321       58,638       54,750       61,594  
Operating leases(2)
    31,520       7,163       8,040       6,079       10,238  
Purchase commitments(3)
    27,890       27,890                    
                                         
Total contractual obligations
  $ 748,713     $  79,374     $ 236,678     $ 60,829     $ 371,832  
                                         
Commercial commitments:
                                       
Long-term debt — standby
                                       
Revolving credit facility
  $ 25,000     $ 25,000                          
standby letters of credit(4)
    16,250       16,250                    
                                         
Total commercial commitments
  $ 41,250     $ 41,250     $     $     $  
                                         
 
 
(1) Long-term debt includes the principal and interest cash obligations of the 9.125% Notes and the 2.125% Notes. The remaining unamortized discount of $9.1 million on the 2.125% Notes is not included in the contractual cash obligations schedule.
 
(2) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.
 
(3) We have purchase commitments outstanding as of December 31, 2010, related to rig upgrade projects and new rig construction.
 
(4) We have an $80.0 million revolving credit facility. As of December 31, 2010, $25.0 million has been drawn down and $16.3 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $38.7 million of availability. The revolving credit facility expires May 14, 2013.


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OTHER MATTERS
 
Business Risks
 
See Item 1A, Risk Factors, for a discussion of risks related to our business.
 
Liberty Project Status
 
In November 2010, BP informed us that it was suspending construction on the Liberty extended reach drilling rig project to review the rig’s engineering and design, including its safety systems. We commenced construction of this rig for BP in April 2008 pursuant to an EPCI contract. In August 2009, BP also awarded us an O&M contract for the first phase of drilling on the Liberty field, which is expected to be a two-year project to drill an ultra extended-reach well, nearly two miles deep and as far as eight miles from the pad. BP has not announced a schedule for resuming construction on the rig or new target dates for drilling and production start-up.
 
The Liberty rig construction contract is a fixed fee and reimbursable contract accounted for on a percentage of completion basis. Costs on the project are reimbursed without markup, except for costs associated with changes in work scope, for which we are entitled to a markup. As of December 31, 2010, we had recognized $325.9 million in project-to-date revenues and $10.9 million in margin of the $11.7 million fixed fee portion of the contract.
 
The Liberty rig construction contract expired on February 8, 2011. Prior to expiration of the construction contract, BP indentified several areas of concern for which it asked us to provide explanations and documentation, and we have done so. Although we believe that the issues raised by BP have been adequately addressed, there can be no assurance of when or how these issues will be resolved with our client. At this point, construction on the rig is incomplete, and it cannot be completed until BP determines to resume construction.
 
The Company and BP have continued activities to preserve and maintain the rig under the “pre-operations” phase of our O&M contract. The O&M contract is scheduled to expire on May 31, 2011, and there can be no assurance that it will be extended.
 
Critical Accounting Policies
 
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.
 
We believe the following are our most critical accounting policies as they are complex and require significant judgments, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.
 
Impairment of Property, Plant and Equipment. We periodically evaluate our property, plant and equipment to ensure that the net realizable value exceeds our net carrying value. We review our property, plant and equipment for impairment annually and when events or changes in circumstances indicate that the carrying value of such assets may be impaired. For example, evaluations are performed when we experience sustained significant declines in utilization and dayrates and we do not contemplate recovery in the near future, or when we reclassify property and equipment to assets held for sale or as discontinued operations as prescribed by accounting guidance related to accounting for the impairment or disposal of long-lived assets. We consider a number of factors, including estimated undiscounted future cash flows, appraisals less estimated selling costs and current market value analysis in determining net realizable value. Assets are written down to fair value if the fair value is below net carrying value.


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Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets. As a result of certain impairment indicators, primarily the depressed international market, we tested our long-lived assets for impairment as of December 31, 2010, noting our estimates of undiscounted future cash flows support the current carrying values of our assets. Therefore, we did not recognize any impairment of our property, plant, and equipment as of December 31, 2010.
 
Insurance Reserves.  Our operations are subject to many hazards inherent to the drilling industry, including blowouts, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, these insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an insurance coverage deductible.
 
Based on the risks discussed above, we estimate our liability in excess of insurance coverage and record reserves for these amounts in our consolidated financial statements. Reserves related to insurance are based on the facts and circumstances specific to the insurance claims and our past experience with similar claims. The actual outcome of insured claims could differ significantly from the amounts estimated. We accrue actuarially determined amounts in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability, automobile liability and health benefits claims. These accruals use historical data based upon actual claim settlements and reported claims to project future losses. These estimates and accruals have historically been reasonable in light of the actual amount of claims paid.
 
As the determination of our liability for insurance claims could be material and is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, management believes that accounting estimates related to insurance reserves are critical.
 
Accounting for Income Taxes.  We are a U.S. company and we operate through our various foreign branches and subsidiaries in numerous countries throughout the world. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be reflected on our income tax returns for the current year, nonresident withholding taxes or changes in prior year tax estimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported on the consolidated balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.


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Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to the expiration of our net operating loss (“NOL”) carryforwards. In the event that our earnings performance projections do not indicate that we will be able to benefit from our NOL carryforwards, valuation allowances are established. We periodically evaluate our ability to utilize our NOL carryforwards and, in accordance with accounting guidance related to accounting for income taxes, will record any resulting adjustments that may be required to deferred income tax expense.
 
We provide for U.S. deferred taxes on the unremitted earnings of our foreign subsidiaries as the earnings are not permanently reinvested.
 
We apply the amendments to accounting standards related to uncertainty in income taxes. This accounting guidance requires that management make estimates and assumptions affecting amounts recorded as liabilities and related disclosures due to the uncertainty as to final resolution of certain tax matters. Because the recognition of liabilities under this interpretation may require periodic adjustments and may not necessarily imply any change in management’s assessment of the ultimate outcome of these items, the amount recorded may not accurately anticipate actual outcome.
 
Revenue Recognition.  We recognize revenues and expenses on dayrate contracts as drilling progresses. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization fees received and related mobilization costs incurred are deferred and amortized over the term of the contract period. Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.
 
Recent Accounting Pronouncements
 
For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Notes to Consolidated Financial Statements — Note 16 — Recent Accounting Pronouncements.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Foreign Currency Exchange Rate Risk
 
Our international operations expose us to foreign currency exchange rate risk. There are a variety of techniques to minimize the exposure to foreign currency exchange rate risk, including customer contract payment terms and the possible use of foreign currency exchange rate risk derivative instruments. Our primary foreign currency exchange rate risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars, which is our functional currency, and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign currency exchange rate risk needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have not had a material impact on our overall results. In situations where payments of local currency do not equal local currency requirements, foreign currency exchange rate risk derivative instruments, specifically foreign currency exchange rate risk forward contracts, or spot purchases, may be used to mitigate foreign exchange rate currency risk. A foreign currency exchange rate risk forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such exchange. We do not enter into derivative transactions for speculative purposes. At December 31, 2010, we had no open foreign currency exchange rate risk or interest rate derivative contracts.
 
Interest Rate Risk
 
We are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our long-term debt is estimated based on quoted market prices where


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applicable, or based on the present value of expected cash flows relating to the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our $300.0 million principal amount of 9.125% Senior Notes due 2018, based on quoted market prices, was $314.3 million at December 31, 2010. The estimated fair value of our $125.0 million principal amount of 2.125% Convertible Senior Notes due 2012 was $119.4 million on December 31, 2010. A hypothetical 100 basis point increase in interest rates relative to market interest rates at December 31, 2010 would decrease the fair market value of our long-term debt at December 31, 2010 by approximately $32.4 million for the 9.125% Senior Notes and $37.0 million for the 2.125% Convertible Senior Notes.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Stockholders
Parker Drilling Company:
 
We have audited the accompanying consolidated balance sheets of Parker Drilling Company and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited the financial statement Schedule II — Valuation and Qualifying Accounts for each of the years in the three-year period ended December 31, 2010. We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these consolidated financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting in Item 9A. Controls and Procedures. Our responsibility is to express an opinion on these consolidated financial statements, the financial statement schedule and the Company’s internal control over financial reporting based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 consolidated 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of 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.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Parker Drilling Company and subsidiaries as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement


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schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also in our opinion, Parker Drilling Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
/s/  KPMG LLP
 
Houston, Texas
February 28, 2011


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PARKER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENT OF OPERATIONS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands, except per share data)  
 
Revenues:
                       
International drilling
  $ 220,371     $ 293,337     $ 325,096  
U.S. drilling
    64,543       49,628       173,633  
Rental tools
    172,598       115,057       171,554  
Project management and engineering services
    110,873       109,445       110,147  
Construction contract
    91,090       185,443       49,412  
                         
Total revenues
    659,475       752,910       829,842  
                         
Operating expenses:
                       
International drilling
    177,585       191,486       231,409  
U.S. drilling
    53,334       48,054       84,431  
Rental tools
    60,036       52,740       67,048  
Project management and engineering services
    89,435       85,799       91,677  
Construction contract
    90,888       177,311       46,815  
Depreciation and amortization
    115,030       113,975       116,956  
                         
Total operating expenses
    586,308       669,365       638,336  
                         
Total operating gross margin
    73,167       83,545       191,506  
                         
General and administration expense
    (30,728 )     (45,483 )     (34,708 )
Impairment of goodwill
                (100,315 )
Provision for reduction in carrying value of certain assets
    (1,952 )     (4,646 )      
Gain on disposition of assets, net
    4,620       5,906       2,697  
                         
Total operating income
    45,107       39,322       59,180  
                         
Other income and (expense):
                       
Interest expense
    (26,805 )     (29,450 )     (29,266 )
Interest income
    257       1,041       1,405  
Loss on extinguishment of debt
    (7,209 )            
Equity in loss of unconsolidated joint venture, net of taxes
                (1,105 )
Other
    155       (1,086 )     (544 )
                         
Total other expense
    (33,602 )     (29,495 )     (29,510 )
                         
Income before income taxes
    11,505       9,827       29,670  
                         
Income tax expense (benefit):
                       
Current tax expense (benefit)
    27,521       15,424       (1,539 )
Deferred tax expense (benefit)
    (1,308 )     (14,864 )     8,481  
                         
Total income tax expense
    26,213       560       6,942  
                         
Net income (loss)
    (14,708 )     9,267       22,728  
Less: Net (loss) attributable to noncontrolling interest
    (247 )            
                         
Net income (loss) attributable to controlling interest
  $ (14,461 )   $ 9,267     $ 22,728  
                         
Basic earnings per share:
  $ (0.13 )   $ 0.08     $ 0.20  
Diluted earnings per share:
  $ (0.13 )   $ 0.08     $ 0.20  
Number of common shares used in computing earnings per share:
                       
Basic
    114,258,965       113,000,555       111,400,396  
Diluted
    114,258,965       114,925,446       112,430,545  
 
See accompanying notes to the consolidated financial statements.


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PARKER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEET
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 51,431     $ 108,803  
Accounts and notes receivable, net of allowance for bad debts of $7,020 in 2010 and $4,095 in 2009
    168,876       188,687  
Rig materials and supplies
    25,527       31,633  
Deferred costs
    2,229       4,531  
Deferred income taxes
    9,278       9,650  
Other tax assets
    46,429       37,818  
Assets held for sale
    5,287        
Other current assets
    59,067       62,407  
                 
Total current assets
    368,124       443,529  
                 
Property, plant and equipment, at cost:
               
Drilling equipment
    996,255       1,004,920  
Rental tools
    269,474       232,559  
Buildings, land and improvements
    31,918       30,548  
Other
    54,806       50,847  
Construction in progress
    338,873       211,889  
                 
      1,691,326       1,530,763  
Less accumulated depreciation and amortization
    875,179       813,965  
                 
Property, plant and equipment, net
    816,147       716,798  
Other assets:
               
Rig materials and supplies
    13,930       9,291  
Debt issuance costs
    9,214       5,406  
Deferred income taxes
    61,016       55,749  
Other assets
    6,124       12,313  
                 
Total other assets
    90,284       82,759  
                 
Total assets
  $ 1,274,555     $ 1,243,086  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Current portion of long-term debt
  $ 12,000     $ 12,000  
Accounts payable
    107,894       95,207  
Accrued liabilities
    50,877       72,703  
Accrued income taxes
    4,492       9,126  
                 
Total current liabilities
    175,263       189,036  
                 
Long-term debt
    460,862       411,831  
Other long-term liabilities
    30,193       30,246  
Long-term deferred tax liability
    20,171       16,074  
Commitments and contingencies (Note 13)
           
Stockholders’ equity:
               
Preferred stock, $1 par value, 1,942,000 shares authorized, no shares outstanding
           
Common stock, $0.162/3 par value, authorized 280,000,000 shares, issued and outstanding, 116,369,044 shares (116,239,097 shares in 2009)
    19,397       19,374  
Capital in excess of par value
    630,409       623,557  
Accumulated deficit
    (61,493 )     (47,032 )
                 
Total controlling interest stockholders’ equity
    588,313       595,899  
Noncontrolling interest
    (247 )      
                 
Total equity
    588,066       595,899  
                 
Total liabilities and stockholders’ equity
  $ 1,274,555     $ 1,243,086  
                 
 
See accompanying notes to the consolidated financial statements.


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PARKER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENT OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income (loss)
  $ (14,708 )   $ 9,267     $ 22,728  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation and amortization
    115,030       113,975       116,956  
Impairment of goodwill
                100,315  
Loss on extinguishment of debt
    7,209              
Gain on disposition of assets
    (4,620 )     (5,906 )     (2,697 )
Deferred tax expense
    (1,308 )     (14,864 )     8,481  
Provision for reduction in carrying value
                       
of certain assets
    1,952       4,646        
Equity loss in unconsolidated joint venture
                1,105  
Expenses not requiring cash
    14,829       11,626       15,333  
Change in assets and liabilities:
                       
Accounts and notes receivable
    20,752       1,656       (14,958 )
Rig materials and supplies
    (856 )     (3,464 )     (11,271 )
Other current assets
    (2,969 )     (29,903 )     (15,737 )
Accounts payable and accrued liabilities
    (10,868 )     29,735       (238 )
Accrued income taxes
    (4,124 )     (13,004 )     (2,404 )
Other assets
    3,231       7,108       2,705  
                         
Net cash provided by operating activities
    123,550       110,872       220,318  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Capital expenditures
    (219,184 )     (160,054 )     (197,070 )
Proceeds from the sale of assets
    6,475       9,336       4,512  
Proceeds from insurance claims
                951  
Investment in unconsolidated joint venture
                (5,000 )
                         
Net cash used in investing activities
    (212,709 )     (150,718 )     (196,607 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Proceeds from issuance of debt
    300,000             50,000  
Proceeds from draw on revolver credit facility
    25,000       4,000       73,000  
Paydown on senior notes
    (225,000 )              
Paydown on term note
    (12,000 )     (6,000 )      
Paydown on revolver credit facility
    (42,000 )     (20,000 )     (35,000 )
Payment of debt issuance costs
    (7,976 )           (1,846 )
Payment of debt extinguishment costs
    (7,466 )              
Proceeds from stock options exercised
    26       199       1,969  
Excess tax benefit (expense) from stock-based compensation
    1,203       (1,848 )     340  
                         
Net cash provided by (used in) financing activities
    31,787       (23,649 )     88,463  
                         
Net increase (decrease) in cash and cash equivalents
    (57,372 )     (63,495 )     112,174  
Cash and cash equivalents at beginning of year
    108,803       172,298       60,124  
                         
Cash and cash equivalents at end of year
  $ 51,431     $ 108,803     $ 172,298  
                         
Supplemental cash flow information:
                       
Interest paid
  $ 30,377     $ 28,721     $ 27,192  
Income taxes paid
  $ 41,064     $ 17,462     $ 45,615  
 
See accompanying notes to the consolidated financial statements.


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PARKER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
 
                                                         
                            Total
             
                Capital in
          Controlling
          Total
 
          Common
    Excess of
    Accumulated
    Stockholders’
    Noncontrolling
    Stockholders’
 
    Shares     Stock     Par Value     Deficit     Equity     Interest     Equity  
    (Dollars and shares in thousands)  
 
Balances, December 31, 2007
    111,916     $ 18,653     $ 609,696     $ (79,027 )   $ 549,322           $ 549,322  
Activity in employees’ stock plans
    1,540       257       2,895             3,152               3,152  
Excess tax benefit from stock based compensation
                340             340               340  
Amortization of restricted stock plan compensation
                6,630             6,630               6,630  
Net income (total comprehensive income of $22,728)
                      22,728       22,728             22,728  
                                                         
Balances, December 31, 2008
    113,456     $ 18,910     $ 619,561     $ (56,299 )   $ 582,172     $     $ 582,172  
Activity in employees’ stock plans
    2,783       464       1,483             1,947               1,947  
Excess tax benefit from stock based compensation
                (1,848 )           (1,848 )             (1,848 )
Amortization of restricted stock plan compensation
                4,361             4,361               4,361  
Net income (total comprehensive income of $9,267)
                      9,267       9,267               9,267  
                                                         
Balances, December 31, 2009
    116,239     $ 19,374     $ 623,557     $ (47,032 )   $ 595,899     $     $ 595,899  
Activity in employees’ stock plans
    130       23       114             137               137  
Excess tax benefit from stock options exercised
                1,203             1,203               1,203  
Amortization of restricted stock plan compensation
                5,535             5,535               5,535  
Net income (total comprehensive net loss of $14,708)
                      (14,461 )     (14,461 )     (247 )     (14,708 )
                                                         
Balances, Dec 31, 2010
    116,369     $  19,397     $ 630,409     $ (61,493 )   $ 588,313     $  (247 )   $ 588,066  
                                                         
 
See accompanying notes to the consolidated financial statements.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
 
Note 1 — Summary of Significant Accounting Policies
 
Nature of Operations — Parker Drilling Company (Parker Drilling), together with its subsidiaries (the Company) is a leading worldwide provider of contract drilling and drilling-related services with extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. At December 31, 2010, our marketable rig fleet consisted of 15 barge drilling rigs and workover rigs, and 25 land rigs, located in the United States, Americas, Middle East, CIS and Asia Pacific regions.
 
Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise significant control or have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. A subsidiary of Parker Drilling has a 50 percent interest in one other company which is accounted for under the equity method as Parker Drilling’s interest in the entity does not meet the consolidation criteria described above.
 
Non-Controlling Interest — Effective January 1, 2009, we adopted the accounting standards update related to noncontrolling interest that established accounting and reporting requirements for (a) noncontrolling interest in a subsidiary and (b) the deconsolidation of a subsidiary. The update required that noncontrolling interest be reported as equity on the consolidated balance sheet and required that net income (loss) attributable to controlling interest and to noncontrolling interest be shown separately on the face of the statement of operations. As a result of our adoption, on our consolidated statements of operations, we have separately presented net (loss) attributable to noncontrolling interest and net income (loss) attributable to controlling interest. Additionally, on our consolidated balance sheet, we reclassified to equity the balance associated with noncontrolling interest.
 
Reclassifications — Certain reclassifications have been made to prior period amounts to conform with the current period presentation. These reclassifications did not have a material effect on our consolidated statement of operations, consolidated balance sheet or statement of cash flows.
 
Revenue Recognition.  We recognize revenues and expenses on dayrate contracts as drilling progresses. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization fees received and related mobilization costs incurred are deferred and amortized over the term of the contract period. Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.
 
Use of Estimates — The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the financial statements, and our revenue and expenses during the periods reported. Estimates are used when accounting for certain items such as legal accruals, mobilization and deferred mobilization, revenue and cost accounting following the percentage of completion method, self-insured medical/dental plans, etc. Estimates are based on historical experience, where applicable, and assumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ.
 
During the third quarter of 2010, we corrected an accounting error relating to value added taxes (VAT) in our Western Kazakhstan branch (PDKBV). In Kazakhstan, companies are permitted to elect the use of either the proportional or separate method for filing periodic VAT returns. PDKBV utilized the proportional method which can limit future recoverability of VAT derived from vendor purchases and rig importation against VAT derived from customer invoicing activities. On the erroneous belief that certain VAT amounts would be recoverable in future periods, PDKBV recorded VAT assets in connection with several transactions occurring during the period 2007 through 2008. However, due to a customer having VAT exempt status, the recoverability of a portion of the VAT assets created was limited, and certain amounts should have been expensed during the periods in which the original transactions occurred. The cumulative effect of the error and related foreign currency translation impact overstated net income and retained earnings by $6.4 million over the period 2007 through 2009. The impact of the error was determined not to be material to our results of operations and financial position for any previously reported periods.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Consequently, during the third quarter of 2010, the cumulative effect of this correction was recorded in operating expenses and is reflected in year to date operating expenses for the year ended December 31, 2010.
 
Reimbursable Costs — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $40.1 million, $41.1 million and $53.3 million during the years ended December 31, 2010, 2009 and 2008, respectively.
 
Cash and Cash Equivalents — For purposes of the consolidated balance sheet and the consolidated statement of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.
 
Accounts Receivable and Allowance for Doubtful Accounts — Trade accounts receivable are recorded at the invoice amount and generally do not bear interest. The allowance for doubtful accounts is our best estimate for losses that may occur resulting from disputed amounts and the inability of our customers to pay amounts owed. We determine the allowance based on historical write-off experience and information about specific customers. We review all past due balances over 90 days individually for collectability.
 
Account balances are charged off against the allowance when we believe it is probable the receivable will not be recovered. We do not have any off-balance-sheet credit exposure related to customers.
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Trade
  $ 175,246     $ 192,782  
Notes receivable
    650        
Allowance for doubtful accounts(1)
    (7,020 )     (4,095 )
                 
Total receivables
  $ 168,876     $ 188,687  
                 
 
 
(1) Additional information on the allowance for doubtful accounts for the years ended December 31, 2010, 2009 and 2008 is reported on Schedule II — Valuation and Qualifying Accounts.
 
Property, Plant and Equipment — We provide for depreciation of property, plant and equipment on the straight-line method over the estimated useful lives of the assets after provision for salvage value. Depreciable lives for different categories of property, plant and equipment are as follows:
 
     
Land drilling equipment
  3 to 20 years
Barge drilling equipment
  3 to 20 years
Drill pipe, rental tools and other
  4 to 7 years
Buildings and improvements
  15 to 30 years
 
When assets are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any gain or loss is included in operations. In the first quarter of 2009, we implemented a change in accounting estimate to more accurately reflect the useful life of some of the long-lived assets in our U.S. drilling and international drilling segments. This resulted in an approximate $16.0 million reduction in the depreciation expense in the year ended December 31, 2009, or $0.14 per share. We extended the useful lives of these long-lived assets based on our review of their service lives, technological improvements in the assets and recent changes to our refurbishment and maintenance practices which helped to extend the lives. Maintenance and repairs are charged to operating expense as incurred.
 
Management periodically evaluates the Company’s assets to determine whether their net carrying values are in excess of their net realizable values. Management considers a number of factors such as estimated future cash flows, appraisals and current market value analysis in determining net realizable value. Assets are written down to fair value if the fair value is below the net carrying value.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. Interest cost capitalized, reduces net interest expense in the consolidated statement of operations. During 2010, 2009 and 2008, we capitalized interest costs related to the construction of rigs of $13.5 million, $6.0 million and $5.1 million, respectively.
 
Assets held for sale — We classify an asset as held for sale when the facts and circumstances meet the required criteria for such classification, including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or termination. At December 31, 2010, we have net assets held for sale, included in current assets, in the amount of $5.3 million. For further information, see Note 3.
 
Goodwill — Goodwill, when recorded upon the result of a qualifying event, is assessed for impairment on at least an annual basis. As of December 31, 2010 there was no existing goodwill. For further information see Note 4.
 
Rig Materials and Supplies — Since our international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs, which would result from such transfers. We classify those parts which are not expected to be utilized in the following year as long-term assets. Rig materials and supplies are valued at the lower of cost or market value.
 
Deferred Costs — We defer costs related to rig mobilization and amortize such costs over the term of the related contract. The costs to be amortized within twelve months are classified as current.
 
Debt Issuance Costs — We typically defer costs associated with debt financings and refinancing, and amortize those costs over the term of the notes.
 
Income Taxes — Income taxes have been provided based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits and other benefits. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are recognized against deferred tax assets unless it is “more likely than not” that the Company can realize the benefit of the net operating loss (NOL) carryforwards and deferred tax assets in future periods.
 
Earnings (Loss) Per Share (EPS) — Basic earnings (loss) per share is computed by dividing net income, by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock and convertible debt are included in the diluted EPS calculation, when applicable.
 
Derivatives and hedging — From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to variability in foreign exchange rates and interest rates. We record derivatives on our consolidated balance sheet, measured at fair value. For derivatives that do not qualify for hedge accounting, we recognize the gains and losses associated with changes in the fair value in current period earnings. We do not enter into derivative transactions for speculative purposes. At December 31, 2010 and 2009, we had no open foreign exchange rate or interest rate derivative contracts.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Concentrations of Credit Risk — Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade receivables with a variety of national and international oil and gas companies. We generally do not require collateral on our trade receivables.
 
At December 31, 2010 and 2009, we had deposits in domestic banks in excess of federally insured limits of approximately $25.9 million and $68.1 million, respectively. In addition, we had deposits in foreign banks, which were not insured at December 31, 2010 and 2009 of $31.1 million and $46.7 million, respectively.
 
Our customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2010, BP and ExxonMobil accounted for approximately 12.4 percent and 11.6 percent of total revenues, respectively.
 
Fair Value of Financial Instruments — The estimated fair value of the Company’s $300.0 million principal amount of 9.125% Senior Notes due 2018, based on quoted market prices, was $314.3 million at December 31, 2010. The estimated fair value, based upon granted prices, of the Company’s $125.0 million principal amount of 2.125% Convertible Senior Notes due 2012 was $119.4 million on December 31, 2010. For cash, accounts receivable, rig supplies and materials and accounts payable, the Company believes carrying value approximates estimated fair value.
 
Stock-Based Compensation — Under our long term incentive plans, we grant restricted stock awards (RSA), restricted stock units (RSU) and performance share units (PSU). For time-based awards, we recognize compensation expense on a straight-line basis through the date the employee is no longer required to provide service to earn the award (the service period). For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basis through the end of the service period. For performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. Share-based compensation expense is recognized, net of an estimated forfeiture rate, which is based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. Our RSA’s and RSU’s are settled in stock upon vesting. Our PSU awards can be settled in cash or stock at the discretion of the compensation committee of the board of directors and are, therefore, accounted for as liability awards under ASC 718, Compensation — Stock Compensation.
 
We utilize the Black-Scholes option-pricing model to estimate the fair value of our stock options. Expected volatility is determined by using historical volatilities based on historical stock prices for a period that matches the expected term. The expected term of options represents the period of time that options granted are expected to be outstanding and typically falls between the options’ vesting and contractual expiration dates. The expected term assumption is developed by using historical exercise data adjusted as appropriate for future expectations. The risk-free rate is based on the yield at the date of grant of a zero-coupon U.S. Treasury bond whose maturity period equals the option’s expected term. The fair value of each option is estimated on the date of grant. There were no option grants during any of the three-years ended December 31, 2010.
 
We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.
 
Note 2 — Disposition of Assets
 
Disposition of Assets — Asset disposition in 2009 included the settlement of claims related to a barge that was overturned in 2005 and the sale of miscellaneous equipment that resulted in a recognized gain of $5.9 million. The single largest asset disposition item included in this category was related to the settlement in lieu of legal action in connection with the overturning of a barge rig that was being towed in advance of Hurricane Dennis in July 2005. The Company settled with various counterparties to the claim in December 2009, and received cash reimbursement, in the amount of $4.0 million, which was recorded as a gain in December 2009 as we had previously written-off the


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
remaining net book value of the barge rig. Asset disposition in 2008 included the sale of Rig 206 in Indonesia, for which we recorded no gain or loss and miscellaneous equipment that resulted in a recognized gain of $2.7 million.
 
There were no individually significant asset dispositions in 2010.
 
Provision for Reduction in Carrying Value of an Asset — In 2010, the Company recognized a $2.0 million provision for reduction in carrying value related to uncollectible accounts receivable. In 2009, we recorded a $4.6 million provision for reduction in carrying value related to certain drilling rigs and equipment that were deemed to no longer be marketable upon changing market conditions and increased competition in the market for which these rigs were working.
 
Note 3 — Assets Held for Sale
 
Assets held for sale of $5.3 million as of December 31, 2010 was comprised of the net book value of three land rigs and related inventory for which sale is expected to be completed in 2011. The three rigs are part of our Asia Pacific rig fleet and have historically been included in the international drilling segment. We expect the carrying amount of the assets, less costs to sell, will be fully recoverable through sale of the assets.
 
Note 4 — Goodwill
 
In 2008, goodwill was evaluated and as a result of then current equity market conditions in which our market capitalization was significantly under the book value of its assets and the uncertainty about financial markets’ return to normalcy, all of the goodwill recorded on our books was written off in 2008.
 
Note 5 — Long-Term Debt
 
The following table illustrates the Company’s current debt portfolio as of December 31, 2010:
 
                 
    December 31,
    December 31,
 
    2010     2009  
    (Dollars in thousands)  
 
Senior Notes Payable in April 2018 with fixed interest at 9.125% payable semi-annually in April and October. 
  $ 300,000     $  
Senior Notes payable in October 2013 with interest at 9.625% payable semi-annually in April and October net of unamortized premium of $2,427 at December 31, 2009. (Effective interest rate of 9.24% at December 31, 2009)
          227,427  
$125.0 million aggregate principal Convertible Senior Notes payable in July 2012 with interest at 2.125% payable semi-annually in January and July, net of unamortized discount of $9,138 at December 31, 2010 and $14,596 at December 31, 2009
    115,862       110,404  
Term Note which began amortizing September 30, 2009 at equal installments of $3.0 million per quarter with interest at prime, plus an applicable margin or LIBOR, plus an applicable margin. (Effective interest rate of 3.50% at December 31, 2010 and 3.48% at December 31, 2009)
    32,000       44,000  
Revolving Credit Facility with interest at prime, plus an applicable margin or LIBOR, plus an applicable margin. (Effective interest rate of 5.25% at December 31, 2010 and 2.98% December 31, 2009)
    25,000       42,000  
                 
Total debt
    472,862       423,831  
Less current portion
    12,000       12,000  
                 
Total long-term debt
  $ 460,862     $ 411,831  
                 


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The aggregate maturities of long-term debt are as follows:
 
  •  2011 — $12.0 million
 
  •  2012 — $137.0 million
 
  •  2013 — $33.0 million
 
  •  2014 — $0 million
 
  •  2015 and thereafter — $300.0 million
 
9.125% Senior Notes, due April 2018
 
On March 22, 2010, we issued $300,000,000 aggregate principal amount of 9.125% Senior Notes due 2018 (9.125% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A. (Trustee). The 9.125% Notes were issued at par with interest payable on April 1 and October 1 of each year, beginning October 1, 2010. Net proceeds from the 9.125% Notes offering were used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013, to repay $42.0 million of borrowings under the revolving credit facility and for general corporate purposes.
 
The 9.125% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 9.125% Notes are jointly and severally guaranteed by substantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenue primarily outside the United States.
 
At any time prior to April 1, 2013, we may redeem up to 35 percent of the aggregate principal amount of 9.125% Notes at a redemption price of 109.125 percent of the principal amount, plus accrued and unpaid interest to the redemption date with the net cash proceeds of certain equity offerings by us. On and after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of 104.563 percent of principal amount, and at redemption prices decreasing each year thereafter to par. If we experience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
 
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets; (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness; (iii) make investments; (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries; (viii) merge or consolidate with other entities; (ix) enter into transactions with affiliates; and (x) engage in certain business activities. Additionally, the indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
 
On June 21, 2010 pursuant to the Registration Rights Agreement among the Company, the guarantors named therein, the initial purchasers of the 9.125% Notes and the Trustee, entered into as of March 22, 2010 in connection with the closing of the 9.125% Notes offering, we filed an exchange offer registration statement with respect to an offer to exchange the 9.125% Notes for substantially identical notes that are registered under the Securities Act. The registration statement was deemed effective by the United States Securities and Exchange Commission (SEC) on September 1, 2010.
 
9.625% Senior Notes, due October 2013
 
As of December 31, 2009, we had outstanding $225.0 million in aggregate principal amount of 9.625% senior notes due 2013 (9.625% Notes). On March 8, 2010, we commenced a cash tender offer and consent solicitation for all of our outstanding 9.625% Notes, which expired on April 2, 2010 (Tender Offer). On March 22, 2010, we voluntarily called for redemption all of our 9.625% Notes that were not tendered pursuant to the Tender Offer, at the redemption price of 103.208 percent of the principal amount of the 9.625% Notes, or $1,032.08 per $1,000 principal


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
amount of the 9.625% Notes. On April 21, 2010, we redeemed in full the remaining $128.7 million principal amount of 9.625% Notes. This redemption resulted in the Company recording debt extinguishment costs of $7.2 million during 2010.
 
2008 Credit Agreement:
 
On May 15, 2008, we entered into a credit agreement (Credit Agreement) consisting of a senior secured $80.0 million revolving credit facility (Revolver) and senior secured term loan facility (Term Loan) of up to $50 million. The Credit Agreement provides that subject to certain conditions, including the approval of the Administrative Agent and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan Facility or Revolving Credit Facility can be increased by an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180.0 million. If the facility is increased, all other terms of the Credit Agreement remain the same, including covenants and Applicable Rates. The Credit Agreement terminates on May 14, 2013.
 
Revolver:
 
Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR, plus an Applicable Rate. The Applicable Rate varies from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75 percent to 2.25 percent for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Revolving loans are available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were $25.0 million and $42.0 million in revolving loans outstanding at December 31, 2010 and December 31, 2009, respectively. Letters of credit outstanding as of December 31, 2010 and December 31, 2009 totaled $16.3 million and $12.7 million, respectively
 
Term Loan:
 
The Term Loan originated at $50.0 million and requires quarterly principal payments of $3.0 million. Interest on the Term Loan accrues at either a Base Rate plus 2.25 percent or LIBOR plus 3.25 percent. The outstanding balances on the Term Loan at December 31, 2010 and December 31, 2009 were $32.0 million and $44.0 million, respectively.
 
Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, each of which has executed guaranty agreements. The Credit Agreement contains customary affirmative and negative covenants for which we were in compliance as of December 31, 2010 and 2009.
 
On January 15, 2010, the Credit Agreement was amended in anticipation of the issuance of 9.125% Notes described above, in order to, among other things, release certain subsidiaries from their obligations under the Credit Agreement, effective upon the repurchase or redemption of all the outstanding 9.625% Notes. These released subsidiaries are our immaterial subsidiaries and subsidiaries generating revenue primarily outside the United States. Upon the effectiveness of the amendment to the Credit Agreement, the guarantors under the Credit Agreement were the same as the guarantors of the 9.125% Notes.
 
2.125% Convertible Senior Notes, due July 2012
 
On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Convertible Senior Notes (the Notes) due July 2012. The Notes were issued at par and interest is payable semi-annually on January 15th and July 15th. As discussed in Note 1, our consolidated financial statements as of and for the three-years ended December 31, 2009 have been adjusted to account for the retrospective application related to newly adopted accounting guidance in regards to accounting for convertible debt instruments that may be settled in cash upon conversion. The debt discount is accretive to interest expense over the life of the debt.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The significant terms of the Notes are as follows:
 
  •  Notes Conversion Feature — the initial conversion price for Note holders to convert their notes into shares is at a common stock share price equivalent of $13.85 (77.2217 shares of common stock) per $1,000 note value. Conversion rate adjustments occur for any issuances of stock, warrants, rights or options (except for stock purchase plans or dividend re-investments) or any other transfer of benefit to substantially all stockholders, or as a result of a tender or exchange offer. We may, under advice of our Board of Directors, increase the conversion rate at our sole discretion for a period of at least 20 days
 
  •  Notes Settlement Feature — upon tender of the Notes for conversion, we can either settle entirely in shares of common stock or a combination of cash and shares of common stock, solely at our option. Our intent is to satisfy our conversion obligation for our Notes in cash, rather than in common stock, for at least the aggregate principal amount of the Notes. This reduces the resulting potential earnings dilution to only include any possible conversion premium, which would be the difference between the average price of our shares and the conversion price per share of common stock.
 
  •  Contingent Conversion Feature — Note holders may only convert the Notes when either sales price or trading price conditions are met, on or after the Notes’ due date or upon certain accounting changes or certain corporate transactions (fundamental changes) involving stock distributions. Make-whole provisions are only included in the accounting and fundamental change conversions such that holders do not lose value as a result of the changes.
 
  •  Settlement Feature — Upon conversion, we will pay either cash or provide shares of our common stock if any, based on a daily conversion rate multiplied by a volume weighted average price of our common stock during a specified period following the conversion date. Conversions can be settled in cash or shares, solely at our discretion.
 
As of December 31, 2010 and 2009, none of the conditions allowing holders of the Notes to convert had been met.
 
Concurrently with the issuance of the Notes, we purchased a convertible note hedge (note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the Notes. The note hedge included purchasing free-standing call options and selling free-standing warrants, both exercisable in our common shares. The note hedge allows us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the Notes upon conversion.
 
The terms of the call options mirror the Notes’ major terms whereby the call option strike price is the same as the initial conversion price as are the number of shares callable, $13.85 per share and 9,027,713 shares, respectively. This feature prevents dilution of our outstanding shares. The warrants allow us to sell 9,027,713 common shares at a strike price of $18.29 per share. The conversion price of the Notes remains at $13.85 per share, and the existence of the call options and warrants serve to guard against dilution at share prices less than $18.29 per share, since we would be able to satisfy our obligations and deliver shares upon conversion of the Notes with shares that are obtained by exercising the call options.
 
We paid a premium of approximately $31.5 million for the call options, and received proceeds for a premium of approximately $20.3 million for the sale of the warrants. This reduced the net cost of the note hedge to $11.2 million. The expiration date of the note hedge is the earlier of the last day on which the Notes remain outstanding or the maturity date of the Notes.
 
The Notes are classified as a liability in our consolidated financial statements. Because we have the choice of settling the call options and the warrants in cash or shares of our common stock and these contracts meet all of the applicable criteria for equity classification, the cost of the call options and proceeds from the sale of the warrants are classified in stockholders’ equity in the Consolidated Balance Sheets. In addition, because both of these contracts


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
are classified in stockholders’ equity and are solely indexed to our own common stock, they are not accounted for as derivatives.
 
Debt issuance costs related to the Notes totaled approximately $3.6 million and are being amortized over the five year term of the Notes using the effective interest method. Proceeds from the transaction of $110.2 million were used to redeem our outstanding senior floating rate notes, to pay the net cost of hedge and warrant transactions, and for general corporate purposes.
 
Note 6 — Income Taxes
 
Income (loss) before income taxes is summarized below:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
United States
  $ 8,985     $ (62,265 )   $ (30,212 )
Foreign
    2,520       72,092       59,882  
                         
    $ 11,505     $ 9,827     $ 29,670  
                         
 
Income tax expense (benefit) is summarized as follows:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Current:
                       
United States:
                       
Federal
  $ (273 )   $ (4,541 )   $ (3,751 )
State
    184       128       407  
Foreign
    27,610       19,837       1,805  
Deferred:
                       
United States:
                       
Federal
    (3,981 )     (14,818 )     8,914  
State
    1,459       (1,793 )     (784 )
Foreign
    1,214       1,747       351  
                         
    $ 26,213     $ 560     $ 6,942  
                         


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Total income tax expense differs from the amount computed by multiplying income before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows:
 
                                                 
    Year Ended December 31,  
    2010     2009     2008  
          % of Pre-Tax
          % of Pre-Tax
          % of Pre-Tax
 
    Amount     Income     Amount     Income     Amount     Income  
    (Dollars in thousands)  
 
Computed Expected Tax Expense
  $ 4,027       35 %   $ 3,439       35 %   $ 10,384       35 %
Foreign Taxes
    18,951       165 %     20,432       208 %     22,391       75 %
Tax Effect Different From Statutory Rates
    (7,996 )     (70 )%     (10,658 )     (108 )%     (4,449 )     (15 )%
State Taxes, net of federal benefit
    1,579       14 %     (1,355 )     (14 )%     (180 )     (1 )%
Foreign Tax Credits
    (15,442 )     (134 )%     (14,152 )     (144 )%     (20,404 )     (69 )%
Kazakhstan Tax Settlement
    13,304       116 %                          
Mexico Tax Settlement
    1,022       9 %                                
Change in Valuation Allowance
    506       4 %     638       6 %     (1,835 )     (6 )%
Foreign Corporation Income
                  5,116       52 %     2,997       10 %
FIN 48 — Uncertain Tax Positions
    983       9 %     2,982       30 %     (13,002 )     (44 )%
State NOL
                  (165 )     (2 )%              
Tax Benefit of Foreign Divestment
                              (3,456 )     (12 )%
Permanent Differences
    6,003       52 %     2,893       29 %     3,189       11 %
Prior Year Return to Provision Adjustments
    1,775       15 %     (3,237 )     (33 )%              
Foreign Tax Credits — Prior Years
                  (5,389 )     (55 )%              
Other
    1,501       13 %     16             (1,329 )     (4 )%
Goodwill
                              12,636       43 %
                                                 
Actual Tax Expense
  $ 26,213        228 %   $ 560        6 %   $ 6,942        23 %
                                                 


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The components of the Company’s deferred tax assets and (liabilities) as of December 31, 2010 and 2009 are shown below:
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
Deferred tax assets
               
Current deferred tax assets:
               
Reserves established against realization of certain assets
  $ 4,287     $ 4,876  
Accruals not currently deductible for tax purposes
    4,991       4,774  
                 
Net current deferred tax assets
    9,278       9,650  
                 
Non-current deferred tax assets:
               
Federal net operating loss carryforwards
    4,337       4,288  
State net operating loss carryforwards
    7,879       6,291  
Other state deferred tax asset, net
    702       4,913  
Foreign Tax Credits
    29,594       14,152  
Other long term liabilities
    369       2,149  
Note Hedge Interest
    4,925       7,204  
Percentage of Completion Construction Projects
    18       17  
Goodwill
    1,156       3,483  
FIN 48
    10,487       11,245  
Foreign tax local
    6,244       6,232  
Other
    837       969  
                 
Gross long-term deferred tax assets
    66,548       60,943  
Valuation Allowance
    (5,532 )     (5,194 )
                 
Net non-current deferred tax assets
    61,016       55,749  
                 
Net deferred tax assets
    70,294       65,399  
                 
Deferred tax liabilities:
               
Non-current deferred tax liabilities:
               
Property, Plant and equipment
    (1,747 )     (1,963 )
Deferred tax impact of Foreign Earnings
    (5,484 )        
Foreign tax local
    (8,912 )     (6,708 )
Federal benefit of foreign tax
    (1,039 )     (1,032 )
Convertible Debt — State
    (46 )     (1,023 )
Convertible Debt — Federal
    (3,198 )     (5,109 )
Deferred compensation
    255       (239 )
                 
Net non-current deferred tax liabilities
    (20,171 )     (16,074 )
                 
Net deferred tax asset
  $ 50,123     $ 49,325  
                 
 
As part of the process of preparing the consolidated financial statements, the Company is required to determine its provision for income taxes. This process involves estimating the annual effective tax rate and the nature and measurements of temporary and permanent differences resulting from differing treatment of items for tax and accounting purposes. These differences and the NOL carryforwards result in deferred tax assets and liabilities. In each period, we assess the likelihood that our deferred tax assets will be recovered from existing deferred tax liabilities or future taxable income in each taxing jurisdiction. To the extent the Company believes that it does not


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
meet the test that recovery is more likely than not, it establishes a valuation allowance. To the extent that the Company establishes a valuation allowance or changes this allowance in a period, it adjusts the tax provision or tax benefit in the consolidated statement of operations. We use our judgment in determining provisions or benefits for income taxes, and any valuation allowance recorded against previously established deferred tax assets.
 
The 2010 results include income tax expense primarily related to an unfavorable ruling by the Atyrau Oblast Court upholding a lower court’s decision allowing the revised Tax Notification to stand as further discussed in Note 11 to the consolidated financial statements, Kazakhstan Ministry of Finance Tax Audit, in the notes to the consolidated financial statements. The Kazakhstan tax matter increased tax expense by approximately $14.5 million ($6.8 million net of anticipated tax benefits), which includes approximately $6.5 million in tax, $4.8 million in interest and $3.2 million in penalties. PKD Kazakhstan intends to submit a further discretionary appeal to the Supreme Court of the Republic of Kazakhstan. In addition, tax expense increased from our settlement of a foreign tax audit for one of our subsidiaries for $1.2 million, which includes approximately $0.6 million of tax, $0.1 million in interest, and $0.5 million in penalties.
 
The 2009 results include a $5.4 million benefit related to our ability to claim foreign tax credits from prior years due to a change from deductions to credits, and additional valuation allowances related to state NOL carryforwards and current year foreign tax credits. After considering all available evidence, both positive and negative, we concluded that a valuation allowance of approximately $0.5 million was appropriate relating to the utilization of our current year foreign tax credits. At December 31, 2009, we had $124 million of gross state NOL carryforwards. For tax purposes, the state NOL carryforwards expire over a 15-year period from December 31, 2010 through 2024 for which a $0.6 million state valuation allowance has been established. During 2009, we paid $17.5 million for income taxes, net of refunds of $6.2 million received during the year.
 
The 2008 results reflect a decrease of $22.5 million in deferred tax liabilities related to the impairment of goodwill. The Company released a valuation allowance relating to foreign tax credits due to the realization of its ability to recognize the benefit for the foreign tax credits. In addition, in 2008, we recognized a $12.2 million benefit related to our ability to claim foreign tax credits from prior years due to a change from deductions to credits. A valuation allowance of $4.1 million was established related to a Papua New Guinea deferred tax asset based on management’s analysis that it was not more likely than not we could realize the benefit in future periods.
 
The company applies the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities.
 
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
 
         
    In Millions  
 
Balance at January 1, 2010
  $ (14.6 )
Additions based on tax positions taken during a prior year
    (3.6 )
Additions based on tax positions taken during the current year
    (3.1 )
Reductions based on tax positions taken during the current year
    0.6  
Settlements
    0.4  
Lapse of statute
    4.8  
         
Balance at December 31, 2010
  $   (15.5 )
         


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
In many cases, our uncertain tax positions are related to tax years that remain subject to examination by tax authorities. The following describes the open tax years, by major tax jurisdiction, as of December 31, 2010:
 
     
Colombia
  2008-present
Kazakhstan
  2005-present
Mexico
  2006-present
Papua New Guinea
  2004-present
Russia
  2007-present
United States — Federal
  1992-present
 
At December 31, 2010, we had a liability for unrecognized tax benefits of $5.8 million (all of which, if recognized, would favorably impact our effective tax rate).
 
The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2010 and December 31, 2009 we had approximately $7.0 million and $9.6 million of accrued interest and penalties related to uncertain tax positions, respectively. We recognized a decrease of $3.4 million of interest and an increase of $0.9 million of penalties on unrecognized tax benefits for the year ended December 31, 2010.
 
Note 7 — Common Stock and Stockholders’ Equity
 
Stock Plans — The Company’s employee and non-employee director stock plans are summarized as follows:
 
The 2010 Long-Term Incentive Plan (2010 Plan) was approved by the stockholders at the Annual Meeting of Stockholders on May 7, 2010. The 2010 Plan authorizes the compensation committee or the board of directors to issue stock options, stock appreciation rights, restricted stock, restricted stock units, performance-based awards and other types of awards in cash or stock to key employees, consultants, and directors. The maximum number of shares of our common stock that may be delivered pursuant to the awards granted under the 2010 Plan is 5,800,000 shares of common stock.
 
The 2005 Long-Term Incentive Plan (2005 Plan) was approved by the stockholders at the Annual Meeting of Stockholders on April 27, 2005. The 2005 Plan authorizes the compensation committee or the board of directors to issue stock options, stock grants and various types of incentive awards in cash or stock to key employees, consultants and directors. During 2008 we obtained stockholder’s approval to increase the total number of common shares available for future awards under the 2005 Plan. This amendment to the 2005 Plan was approved by stockholders at our Annual Meeting on March 21, 2008.
 
In 2010 and 2009, we issued 2,278,189 and 2,483,239, respectively, restricted shares to selected key personnel. Incentive grants to senior management members included in this issuance were based on the attainment of pre-established performance goals. Total stock-based compensation expense recognized for the years ended December 31, 2010, 2009, and 2008 was $5.5 million, $4.6 million, and $7.0 million, respectively, all of which was related to non-vested stock. Stock-based compensation expense is included in our consolidated condensed statements of operations in both “General and administration expense” and “Operating expenses.”
 
Non-vested restricted stock awards and restricted stock units at December 31, 2010 and 2009 were 3,469,163 shares and 2,745,762 shares, respectively. Total unrecognized compensation cost related to unamortized non-vested stock awards was $6.8 million as of December 31, 2010 and $2.9 million as of December 31, 2009. The remaining unrecognized compensation cost related to non-vested stock awards will be amortized over a weighted-average vesting period of approximately 20 months.
 
For the year ended December 31, 2010, the restricted stock vestings resulted in a tax benefit that was more than the deferred tax asset previously recognized. As a result, an excess tax benefit of $1.2 million was recorded to “Capital in excess of par value.”


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
During the year ended December 31, 2010, we granted to certain of our officers and key employees a total of 35,236 and 46,015 performance share units under the 2005 Long Term Incentive Plan and the 2010 Long Term Incentive Plan, respectively. Each performance share unit has a nominal value of $100.00 and represents a contingent right to receive common stock or cash dependent upon our total stockholder return and return on capital employed relative to a peer group of companies over a three-year performance period. The awards are payable in cash or the Company’s common stock at the discretion of the compensation committee. A maximum of 200 percent of the number of performance shares granted may be earned if performance at the maximum level is achieved. Compensation expense related to the performance shares for the year ended December 31, 2010 was $2.7 million.
 
Information regarding the Company’s stock option plans is summarized below:
 
                                                 
    1997 Stock Plan  
    Incentive Options           Non-Qualified Options        
          Weighted
          Weighted
             
          Average
          Average
             
          Exercise
          Exercise
    Restricted
    Intrinsic
 
    Shares     Price     Shares     Price     Shares     Value  
 
Outstanding at December 31, 2009
        $       130,300     $ 3.59                
Granted
                                     
Exercised
                (6,800 )     3.78           $ 11,424  
Cancelled
                (25,000 )     1.99                
                                                 
Outstanding at December 31, 2010
      —     $   —       98,500     $   3.98         —          
                                                 
 
The following tables summarize the information regarding stock options outstanding and exercisable as of December 31, 2010:
                                         
            Outstanding Options    
            Weighted
       
            Average
  Weighted
   
            Remaining
  Average
  Aggregate
        Number of
  Contractual
  Exercise
  Intrinsic
Plan
  Exercise Prices   Shares   Life   Price   Value
 
1997 Stock Plan
Non-qualified
  $ 3.34 - $4.20       98,500       0.43 years     $ 3.98     $ 58,115  
 
                                 
        Exercisable Options    
            Weighted
   
            Average
  Aggregate
        Number of
  Exercise
  Intrinsic
Plan
  Exercise Prices   Shares   Price   Value
 
1997 Stock Plan
Non-qualified
  $ 3.34 - $4.20       98,500     $ 3.98     $ 58,115  
 
The Company had 1,631,511 and 1,574,176 shares held in treasury stock at December 31, 2010 and 2009, respectively.
 
Stock Reserved for Issuance — The following is a summary of common stock reserved for issuance:
 
                 
    December 31,
    2010   2009
 
Stock plans
    9,441,168       3,738,679  
Stock bonus plan
    24,666       24,666  
                 
Total shares reserved for issuance
    9,465,834       3,763,345  
                 


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 8 — Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings per Share (EPS)
 
                         
    For the Year Ended December 31, 2010  
    Income
    Shares
    Per-Share
 
    (Numerator)     (Denominator)     Amount  
 
Basic EPS
  $ (14,461,000 )     114,258,965     $   (0.13 )
Effect of dilutive securities:
                       
Stock options and restricted stock
              $  
                         
Diluted EPS
  $ (14,461,000 )     114,258,965     $  (0.13 )
 
                         
    For the Year Ended December 31, 2009  
    Income
    Shares
    Per-Share
 
    (Numerator)     (Denominator)     Amount  
 
Basic EPS
  $  9,267,000       113,000,555     $ 0.08  
Effect of dilutive securities:
                       
Stock options and restricted stock
          1,924,891     $  
                         
Diluted EPS:
  $ 9,267,000       114,925,446     $   0.08  
 
                         
    For the Year Ended December 31, 2008  
    Income
    Shares
    Per-Share
 
    (Numerator)     (Denominator)     Amount  
 
Basic EPS
  $ 22,728,000       111,400,396     $   0.20  
Effect of dilutive securities:
                       
Stock options and restricted stock
          1,030,149     $  
                         
Diluted EPS:
  $ 22,728,000       112,430,545     $ 0.20  
 
For the year ended December 31, 2010, all potential common shares have been excluded from the calculation of diluted EPS as the company incurred a loss for the year, and therefore, inclusion of potential common shares in the calculation of diluted EPS would be anti-dilutive.
 
For the year ended December 31, 2009, options to purchase 58,500 shares of common stock at a price of $4.20 were outstanding during the period but were not included in the computation of diluted EPS because the options’ exercise prices were greater than the average market price of the common shares.
 
For the year ended December 31, 2008, all stock options outstanding were included in the computation of diluted EPS as the options’ exercise prices were less than the average market price of the common shares.
 
Note 9 — Employee Benefit Plan
 
The Company sponsors a defined contribution 401(k) plan (Plan) in which substantially all U.S. employees are eligible to participate. Company matching contributions to the Plan are based on the amount of employee contributions. The costs of our matching contributions to the Plan were $2.4 million, $2.3 million and $2.8 million in 2010, 2009 and 2008, respectively. Employees become 100 percent vested in the employer match contributions within three months of service from date of hire.


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 10 — Reportable Segments
 
We have established five reportable segments: international drilling, U.S. drilling, rental tools, project management and engineering services, and construction contract. We evaluate performance and allocate resources based on income from continuing operations before income taxes. The following table represents the results of operations by reportable segment:
 
                         
    Year Ended December 31,  
Operations by Reportable Industry Segment
  2010     2009     2008  
    (Dollars in thousands)  
 
Revenues:
                       
International drilling(1)
  $ 220,371     $ 293,337     $ 325,096  
U.S. drilling(1)
    64,543       49,628       173,633  
Rental tools(1)
    172,598       115,057       171,554  
Project management and engineering services(1)
    110,873       109,445       110,147  
Construction contract(1)
    91,090       185,443       49,412  
                         
Total revenues
    659,475       752,910       829,842  
                         
Operating income:
                       
International drilling(2)
    (11,511 )     50,723       41,786  
U.S. drilling(2)
    (11,503 )     (26,797 )     53,964  
Rental tools(2)
    74,541       27,841       74,689  
Project management and engineering services(2)
    21,438       23,646       18,470  
Construction contract(2)
    202       8,132       2,597  
                         
Total operating gross margin
    73,167       83,545       191,506  
General and administrative expense
    (30,728 )     (45,483 )     (34,708 )
Impairment of goodwill
                (100,315 )
Provision for reduction in carrying value of certain assets
    (1,952 )     (4,646 )      
Gain on disposition of assets, net
    4,620       5,906       2,697  
                         
Total operating income
    45,107       39,322       59,180  
Interest expense
    (26,805 )     (29,450 )     (29,266 )
Loss on extinguishment of debt
    (7,209 )            
Equity in loss of unconsolidated joint venture, net of taxes
                (1,105 )
Other
    412       (45 )     861  
                         
Income before income taxes
  $ 11,505     $ 9,827     $ 29,670  
                         
Identifiable assets:
                       
International drilling
  $ 454,576     $ 511,716          
U.S. drilling
    113,548       132,386          
Rental tools
    178,193       96,469          
                         
Total identifiable assets
    746,317       740,571          
Corporate assets
    528,238       502,515          
                         
Total assets
  $ 1,274,555     $ 1,243,086          
                         
 
 
(1) In 2010, BP accounted for approximately 12.4 percent of the Company’s total revenues and approximately $81.9 million of our construction contract segment revenues. In 2010, ExxonMobil accounted for


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approximately 11.6 percent of our total revenues, approximately $63.7 million of our project management and engineering services segment revenues and approximately $12.7 million of our rental tools segment revenues. In 2009, BP accounted for approximately 23.0 percent of the Company’s total revenues, approximately $150.3 million of our construction contract segment revenues and approximately $2.6 million of our rental tools segment revenues. In 2009, ExxonMobil accounted for approximately 14.6 percent of the Company’s total revenues, approximately $75.7 million of our project management and engineering services segment revenues and approximately $20.7 million of our rental tools segment revenues. In 2008, ExxonMobil accounted for approximately 12.5 percent of the Company’s total revenues, approximately $62.2 million of our project management and engineering services segment revenues and approximately $22.3 million of our rental tools segment revenues.
 
(2) Operating income is calculated as revenues less direct operating expenses, including depreciation and amortization expense.
 
                         
    Year Ended December 31,  
Operations by Reportable Industry Segment
  2010     2009     2008  
    (Dollars in thousands)  
 
Capital expenditures:
                       
International drilling
    50,871     $ 29,864     $ 75,680  
U.S. drilling
    117,713       86,943       82,396  
Rental tools
    48,872       36,822       36,806  
Corporate
    1,728       9,155       2,188  
                         
Total capital expenditures
  $ 219,184     $ 162,784     $ 197,070  
                         
Depreciation and amortization:
                       
International drilling
  $ 52,429     $ 48,383     $ 50,461  
U.S. drilling
    22,165       29,200       34,469  
Rental tools
    36,558       33,798       29,057  
Corporate
    3,878       2,594       2,969  
                         
Total depreciation and amortization
  $ 115,030     $ 113,975     $ 116,956  
                         
 


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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Year Ended December 31,  
Operations by Geographic Area
  2010     2009     2008  
    (Dollars in thousands)  
 
Revenues:
                       
Africa and Middle East
  $ 22,621     $ 32,003     $ 40,036  
Asia Pacific
    26,416       33,883       56,998  
CIS
    149,963       195,807       210,325  
Latin America
    103,885       117,651       122,521  
United States
    356,590       373,566       399,962  
                         
Total revenues
    659,475       752,910       829,842  
                         
Operating income:
                       
Africa and Middle East(1)
    659       (2,795 )     (13,293 )
Asia Pacific(1)
    2,374       </