Parker Drilling 10K 2009 Annual report

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, 2009
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 ofRegulation 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 ofRegulation 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 thisForm 10-K or any amendment to thisForm 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 Rule12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act). Yes o No þ

The aggregate market value of our common stock held by non-affiliates on June 30, 2009 was $488.1 million. At January 29, 2010, there were 116,243,899 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 7, 2010 are incorporated by reference in Part III.

TABLE OF CONTENTS


			Page

PART I
	Item 1.	Business		3
	Item 1A.	Risk Factors		13
	Item 1B.	Unresolved Staff Comments		25
	Item 2.	Properties		25
	Item 3.	Legal Proceedings		27
	Item 4.	Reserved		27

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28
	Item 6.	Selected Financial Data		29
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		46
	Item 8.	Financial Statements and Supplementary Data		48
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		88
	Item 9A.	Controls and Procedures		88
	Item 9B.	Other Information		89

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		89
	Item 11.	Executive Compensation		89
	Item 12.	Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters		89
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		89
	Item 14.	Principal Accounting Fees and Services		90

PART IV
	Item 15.	Exhibits and Financial Statement Schedules		90
Signatures				94
EX-10.N.3
EX-21
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 a leading worldwide provider of contract drilling and drilling-related services. Since beginning operations in 1934, we have operated in 53 foreign countries and the United States, 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 policies and procedures are among the leaders in our industry.

Our 2009 revenues are derived from five segments:


	•	International Drilling, including land drilling and inland barge drilling;

	•	U.S. Drilling;

	•	Rental Tools;

	•	Project Management and Engineering Services; and

	•	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, 2009, our company-owned fleet of rigs consisted of:


	•	eleven rigs in the Commonwealth of Independent States/Africa-Middle East (“CIS/AME”) region, including eight land rigs and one arctic-class barge rig in Kazakhstan and two land rigs in Algeria;

	•	ten rigs in the Americas region, including seven land rigs and one barge rig in Mexico and two land rigs in Colombia;

	•	eight land rigs in the Asia Pacific region, including four rigs in Indonesia, two rigs in Papua New Guinea and two rigs in New Zealand;

	•	thirteen barge drilling rigs in the inland and shallow waters of the U.S. Gulf of Mexico (“GOM”); and

	•	one unassigned land rig currently held in our construction yard in New Iberia, Louisiana.

In 2008, we began the construction of two new build rigs designed to operate efficiently in the Alaskan environment. These rigs are expected to be delivered to Alaska in mid-2010 to begin drilling on long-term contracts for our customer, BP. We believe there is a growing need for rigs of this type in the Alaskan market.

Our Rental Tools Business

Our subsidiary, Quail Tools, L.P., (Quail Tools) provides premium rental tools for land and offshore oil and gas drilling and workover activities. Quail Tools offers a full line of drill pipe, drill collars, tubing, high- and low-pressure blowout preventers, choke manifolds, junk and cement mills and casing scrapers. Approximately 20 percent of Quail Tools’ revenues are derived from equipment utilized in offshore and coastal water operations

of the GOM. Quail Tools’ base of operations is in New Iberia, Louisiana. Other facilities are located in Texas, Wyoming, North Dakota and Pennsylvania. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the major U.S. energy producing markets on land and in the GOM. Quail Tools has been increasing tool rentals to customers operating internationally in countries including Angola, Brazil, Canada, Chad, Congo, Egypt, Equatorial Guinea, Libya, Mexico, Sakhalin Island, Russia and the United Arab Emirates.

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 (such as labor, maintenance, logistics, etc.) for operators who own their own drilling rigs and who choose to engage our technical expertise to perform contracted drilling operations. We are currently involved in one Pre-FEED study project and detailed engineering and procurement phase of the Arkutun Dagi project for Exxon Neftegas Limited (“ENL”) and have O&M and project management activities in Alaska, Kuwait and Sakhalin Island, Russia.

Our Construction Contract Business

In 2008, we were awarded the EPCI phase of the BP-owned Liberty extended reach drilling rig project. The rig is scheduled to commence drilling mid-year 2010. We believe the Liberty rig will be one of the most technologically advanced drilling rigs in the world, capable of drilling ultra-extended reach wells nearly two miles deep and as far as eight miles out from the drilling pad.

Our Market Areas

International Markets (including Alaska). The majority of the international drilling markets in which we operate have one or more of the following characteristics:


	•	customers who typically are large independent, national energy companies, or integrated service providers;

	•	drilling programs in remote locations with little infrastructureand/or harsh environments requiring specialized drilling equipment with a large inventory of spare parts and other ancillary equipment and self-supported service capabilities; and

	•	difficult (i.e., high pressure, deep depths, hazardous or geologically challenging) wells requiring specialized equipment and considerable experience to drill.

Typically, our international contracts have multi-year terms.

U.S. Gulf of Mexico and Inland Waterways. The drilling industry in the GOM is characterized by highly cyclical activity where utilization and dayrates are typically driven by current oil and natural gas prices. Within this area, we operate barge rigs primarily in shallow water in and along the inland waterways and coasts of Louisiana and Texas. Historically, two-thirds of our barge rigs, including our three ultra-deep drilling barge rigs, are usually contracted by oil and gas companies to drill natural gas prospects, and one-third to drill oil prospects. However, in today’s market, we have experienced a shift where two-thirds of activity is related to drilling for oil and one-third to drilling for natural gas. These contracts are typicallywell-to-well, with durations averaging 30 to 150 days. In a strong market, driven by high commodity prices, terms can extend up to twelve months and longer.

U.S. Land Market. The market for rental tools is primarily U.S. land drilling, a highly cyclical market driven by oil and natural gas prices and availability of financing. The customer base is very fragmented and includes large major oil companies and many independents of various sizes. Since tools are rented on a daily basis and are often used for only a portion of a well drilling program, they are requested by the customer at the time they are needed, requiring rental tool companies to keep a broad inventory of tools and to have them available for delivery within a time acceptable to the rig operator. In addition, unconventional lateral or horizontal drilling, often used in drilling shale formations, generally employs more rental tools than does conventional vertical drilling, which is an attractive

market for our rental tools segment. As a result, our rental tool market areas are those within a short delivery range of our inventory locations and are focused in the regions of the primary shale plays.

Our Strategy

Our strategy is to achieve and maintain market leadership as a leading worldwide provider of drilling and drilling-related services and products, rental tools, 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 the Parker Drilling brand by leveraging our core competencies, or “four pillars” as described below to provide best value solutions; and to exercise financial discipline and maintain a strong balance sheet. 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 throughout the energy business cycle by building, upgrading and maintaining a fleet of rigs that we expect to be preferred based on quality and dependability and through strategic placement in areas we believe evidence long-term 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 and recent successes in this area; growing our rental tools operation by locating new service facilities in markets with growing demand from existing customers; adding new equipment to our drilling rig fleet that enhances our position of preference by operators; and entering new markets that align with the products and services we offer.

Differentiating the Parker 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: Our industry-leading safety performance is a crucial factor in our status as a preferred drilling contractor. We have a portfolio of tools and proactive measures we apply to reinforce and continually improve our safety 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.

Technology: We have a75-year legacy of developing new technologies for drilling in frontier environments. Our rigs have 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, reduce environmental impacts, and enhance safety.

Performance: A primary aim is to provide services that benefit both the operator and our company. We strive to achieve this by planning, executing and measuring our performance against our goals and our customers’ expectations. We have aligned performance metrics to our business practices tailored to our operations and regularly share them with our customers.

Maintaining Financial Discipline. We strive to maintain strong financial controls and disciplines in every aspect of our business to ensure that our internal assessment of projects and plans adhere to solid financial principles and to assure reasonable debt to equity ratios. Our operating philosophy emphasizes continuous improvement of processes, equipment standardization and global quality, safety, and supply chain

management, and vigilance in monitoring and controlling costs. Capital expenditures are aligned with core objectives. 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.” These principles are intended to lead tostronger-than-peer financial performance in terms of capital utilization and generation of value to our shareholders while allowing operational effectiveness.

2009 Strategic Actions.

In 2009 the following actions, among others, were the direct result of implementing our strategy:


	•	Our International Drilling segment significantly improved its operating gross margin as a percent of revenues, to 35 percent for 2009 from 29 percent for 2008, as it gained, or made progress in gaining, market leadership in select international markets. Creating the critical mass to develop market leadership grew from our previous actions to cluster rigs in markets selected for their current employment of sufficient rigs, thereby allowing us to leverage our operating infrastructure and expectations for further growth;

	•	Our U.S. Barge Drilling business pushed into a leadership position in the GOM inland and shallow water drilling market as a result of both its past investments to overhaul and upgrade its fleet to standards that provided efficient and safe performance that has been preferred by operators and its actions to keep its rigs available and work-ready to capture more of the available work during the recent market downturn;

	•	Our U.S. Barge Drilling business achieved a slightly favorable cash flow despite an exceptional decline in its market by selective cost reduction actions, innovative crew retention programs and assertive marketing, leveraged by its position as a “preferred” contractor in the industry.

	•	We began construction of two high-efficiency, arctic-class land rigs that are scheduled to enter the Alaska market in 2010 under long term contracts;

	•	Our rental tools business segment commissioned a satellite operation in Pennsylvania, with plans to expand to a full-scale facility when activity levels justify it, to serve the emerging demand from operators drilling the Marcellus shale formation;

	•	We were awarded the O&M contract for the operation of the BP-owned Liberty Land rig to drill the Liberty field six miles offshore the Alaskan North Slope; and

	•	We established a new, modern training facility, the Parker Drilling Training Center, in Anchorage, Alaska. This facility complements our training facility in New Iberia, Louisiana, both of which use advanced tools to provide training in a wide range of drill rig operations and procedures;

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:

Geographically Diverse Operations and Assets. We currently operate or manage rigs in Algeria, Colombia, Indonesia, Kazakhstan, Kuwait, Mexico, New Zealand, Russia, and the United States. Since our founding in 1934, we have operated in 53 foreign countries and the United States, making us among the most geographically diverse and experienced drilling contractors in the world. Our international drilling revenues constituted approximately 50 percent of our total revenues for the year ended December 31, 2009.

Outstanding Safety, Planned Maintenance, Inventory Control and Training Programs. We have an outstanding safety record. In 2009, we achieved the lowest Total Recordable Incident Rate (“TRIR”) in our history. Our safety record, as evidenced by our low TRIR, has made us a leader in occupational injury prevention. 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. In recognition of our achievements we were named one of America’s Safest Companies by Occupational Hazards magazine in 2007. 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 to drilling rigs owned by third parties. Our training centers in Louisiana and Alaska provide safety and technical training curriculums in four different languages and provide regulatory compliance training throughout the world.

Technological Leadership. We have demonstrated technological leadership within the drilling industry. We have previously established records for drilling depths including breaking the then extended-reach drilling record in 2008 at Sakhalin Island, Russia. This well reached over seven miles under the sea floor with the Yastreb, a rig designed, built and operated by us. We continue to perform contracts that require technological leadership such as the FEED contract to design a rig for BP to develop the Liberty Field six miles offshore the Alaskan North Slope, Alaska, which we were awarded in 2006. In July 2008, we were awarded the EPCI contract to construct and commission this rig, and in August 2009 we were awarded the O&M contract for the first phase of drilling at Liberty Field.

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 Parker Drilling 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 new chief executive officer and a member of the board of directors effective 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 experience to our drilling operations which enhances our ability to achieve our goals. Our chief financial officer, W. Kirk Brassfield, joined Parker Drilling 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 19 years in the energy industry. Denis Graham, vice president-engineering, brings more than 30 years of experience in drilling industry engineering design, maintenance and regulatory compliance and has established an excellent reputation for Parker Drilling through management of large engineering projects for major oil companies. Mike Drennon, our vice president-operations, brings over 30 years of experience in the oil and gas industry. Mr. Drennon joined Parker Drilling in 2005 from BP and Amoco where he had worked since 1977.

Project Management

We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we designed, constructed and sold a rig to ENL and currently manage drilling operations under a multi-year O&M contract. This rig has drilled one of the world’s longest extended reach wells from Sakhalin Island, reaching out over seven miles under the sea floor for a total measured depth of 38,322 feet. We also operate a second rig to drill from the Orlan platform under an O&M contract for ENL offshore Sakhalin Island, Russia.

During 2006 we began working on a technical service FEED study for BP to provide a conceptual design for a land-based drilling rig targeting the Liberty Field six miles offshore the Alaskan North Slope. Parker Drilling, through an affiliate, commenced construction of this rig for BP pursuant to an EPCI contract in 2008. We are working closely with BP on the final establishment of the rig on the North Slope of Alaska. Parker Drilling Arctic Operating, Inc. in August 2009, was awarded the O&M contract for the rig from BP, which will include the drilling of ultra extended-reach wells, nearly two miles deep and as far as eight miles from the pad.

We also provided labor services on third party-owned drilling rigs in Kuwait and China during 2009 and 2008.

Customers

Our customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2009 our two largest customers, BP and ExxonMobil (including subsidiaries and joint ventures of each), accounted for approximately 26 percent and 15 percent of our total revenues, respectively. Our ten most significant customers collectively accounted for approximately 75 percent of our total revenues in 2009.

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 U.S. based 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, experience and safety record. 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.

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 warm-stack rigs, a standby mode of operational readiness where the Company’s support costs are reduced, while the equipment is maintained in a near market ready condition for quick return to operations, which has led to a more efficient and safer operation. During the 2009 downturn in business, we believe, from reliable market information, that the total marketable barge rig fleet was reduced significantly.

Our management believes that Quail Tools is one of the leading rental tools companies in the offshore GOM and other major U.S. energy producing markets. Quail Tools competes against other rental tool companies based on price and quality of service.

An increasing trend indicates that 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 or alliances 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 are currently a preferred contractor for operators in certain U.S. and international locations which our management believes is a result of our reputation for providing efficient, safe, environmentally conscious and innovative drilling services, in addition to the quality of 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, 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.

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 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. Otherwise, our business activities are not typically affected by unanticipated seasonal fluctuations.

Insurance and Indemnification

In our drilling contracts, we generally seek to obtain indemnification from our customers for some of the risks related to our drilling services. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third party general liability coverage, employer’s liability, environmental and pollution coverage and other coverage. We believe that our insurance coverage is customary for the industry and adequate for our business. However, there are risks against which insurance will not adequately protect us or insurance may not be available to cover any or all of the potential liability arising from all of the consequences and hazards we may encounter in our drilling operations. See Item 1A, “Risk Factors” for additional information.

Employees

The following table sets forth the composition of our employee base:


	December 31,
	2009		2008

International drilling		1,409		1,801
Alaska(1)		140		25
U.S. Barge Drilling		347		420
Rental tools		240		280
Project Management and Engineering Services, Construction Contracts and Corporate		236		240

Total employees		2,372		2,766


(1)		Our employees in Alaska are supporting the business expansion into this region. We currently intend to include our Alaska operations within the International Drilling segment for external reporting purposes as these operations (which include severe conditions, extended-reaching drilling, support camp on site) reflect more closely the characteristics of our international operations than the existing GOMU.S.-based barge operations.

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 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 U.S. Minerals Management Service 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. drilling rigs have zero-discharge capabilities as required by law, e.g. 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 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, 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 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. The United States Congress is also actively considering legislation to reduce emissions of GHGs. In addition, at least 17 states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventoriesand/or regional GHG cap and trade programs. On October 30, 2009, EPA published a final rule requiring the reporting of GHG emissions from specified large sources in the United States beginning in 2011 for emissions occurring in 2010. In addition, on December 15, 2009, EPA published a Final Rule finding that current and projected concentrations of six key GHGs in the atmosphere threaten public health and welfare of current and future generations. EPA also found that the combined emissions of these GHGs from new motor vehicles and new motor vehicle engines contribute to the GHG pollution that threatens public health and welfare. This Final Rule, also known as EPA’s Endangerment Finding, does not impose any requirements on industry or other entities directly; however, the effectiveness of the rule on January 14, 2010 allows the EPA to finalize motor vehicle GHG standards, the effect of which could reduce demand for motor fuels refined from crude oil. Finally, according to EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. As a result, EPA has proposed to tailor these programs such that only stationary sources, including refineries, that emit over 25,000 tons of GHGs per year will be subject to air permitting requirements. In addition, on September 22, 2009, EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”). The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on afacility-by-facility basis. Further, proposed legislation has been introduced in Congress that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. New legislation or regulatory programs that restrict emissions of

GHGs in areas where we conduct business could adversely affect our operations and the demand for hydrocarbon products generally. Moreover, incentives to conserve or use alternative energy sources could reduce demand for fossil fuels, resulting in a decrease in demand for our drilling and drilling related services. The impact of such future programs cannot be predicted, but we do not expect material adverse affects to our operations at this time.

Climate change also poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make estimating any future financial risk to our operations caused by these physical risks of climate change extremely challenging.

The drilling industry is dependent on the demand for services from the oil and gas exploration and development industry, and accordingly, is affected by changes in laws and policies relating to the energy business. Our business is affected generally by political developments and by federal, state, local and foreign regulations that may relate directly to the oil and gas industry. The adoption of laws and regulations, both U.S. and foreign, that curtail exploration and development drilling for oil and gas for economic, environmental and other policy reasons may adversely affect our operations by limiting available drilling opportunities.

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 Contracts. Information about our reportable segments and operations by geographic areas for the years ended December 31, 2009, 2008 and 2007 is set forth in Note 12 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., 61, is the executive chairman of the board of directors. Mr. Parker joined Parker Drilling 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, 52, is president, chief executive officer and member of the board of directors. Mr. Mannon joined Parker Drilling in 2004 as senior vice president and chief operating officer, 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, 54, was elected senior vice president and chief financial officer in 2005. Mr. Brassfield joined Parker Drilling in 1998 as controller and principal accounting officer, and was appointed vice president, finance and accounting in 2001. 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, 42,joined Parker Drilling 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.


	•	Denis J. Graham, 60, joined Parker Drilling 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 Parker Drilling. Mr. Graham is a Registered Professional Engineer in the State of Texas.

	•	Michael D. Drennon, 54, joined Parker Drilling in 2005 as vice president, operations. From 2000 to 2005, Mr. Drennon served as program director for development of company-operated discoveries in Angola for BP. Mr. Drennon served in various engineering, operations and management assignments from 1977 to 2000 with Amoco and BP.

	•	Philip A. Schlom, 45, joined Parker Drilling 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 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 served at the public accounting firm PricewaterhouseCoopers.

Other Parker Drilling Company Officers


	•	David W. Tucker, 54, treasurer, joined Parker Drilling 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 in 1999.

	•	J. Daniel Chapman, 39, joined Parker Drilling in 2009 as chief compliance officer and counsel. Prior to joining Parker Drilling, 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, most recently, as its global ethics & compliance director. Prior to 2002, Mr. Chapman was employed as a securities and merger 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 onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 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 athttp://www.sec.gov.


ITEM 1A.	*RISK FACTORS*

The contract drilling, project management and engineering services, and rental tools businesses involve a high degree of risk. You should consider carefully the risks and uncertainties described below and the other information included in thisForm 10-K, including the financial statements and related notes, 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 occur, our business, financial condition or results of operations could be adversely affected.

Risks Related to Our Business

Continued instability in the global economy may result in an extended decrease in 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.

Over the past 18 months, corporate credit availability and capital market access has been volatile and uncertain, leading to periods of liquidity shortages for industrial businesses worldwide. Although recent economic trends appear to have stabilized and public debt markets were active in the second half of 2009, bank credit

availability continues to remain tight. Increased instability in the financial and insurance markets could make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate or are required by our contracts. Meanwhile, a slowdown in economic activity would likely reduce worldwide demand for energy and result in an extended period of 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. Oil and gas prices have remained at lower levels during the past twelve months in this tough global economic environment and any prolonged reduction in crude oil and natural gas prices will depress the levels 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 revenues 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. The continued weak global economic environment also could impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. Continued volatility in oil and natural gas prices and overall global economic conditions 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 often have to make upgrade and refurbishment expenditures for our rig fleet to comply with our quality management and planned maintenance system or contractual requirements or when repairs are required or to comply with environmental 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 and raw materials, particularly steel;

	•	disputes with shipyards and suppliers;

	•	latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;

	•	financial or other difficulties at shipyards and suppliers;

	•	loss of revenue associated with downtime to remedy malfunctioning equipment not covered by warranty;

	•	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;

	•	unanticipated cost increases; and

	•	inability to obtain the required permits or approvals, including import/export documentation.

Significant cost overruns or delays 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, result in delay in contract commencement, 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 the skilled 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. In addition, labor costs may increase. 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 ability to service our debt obligations is primarily dependent upon our future financial performance.

As of December 31, 2009, we had:


	•	$411.8 million of long-term debt and $14.6 million of additional amount due upon maturity which has been reclassed to equity pursuant to the newly adopted accounting for convertible debt instruments;

	•	$12.0 million of current portion of long-term debt;

	•	$25.1 million of operating lease commitments; and

	•	$12.7 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, general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control.

If we are unable to service our debt obligations, we may have to take one or more of the following actions:


	•	delay spending on maintenance projects and other capital projects, including 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 contained in the documentation contained in our 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 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 creating 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 2010 will be approximately $150 to $175 million, consisting of approximately $70 to $80 million for maintenance projects and rental tool investments. 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 9.625% 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.

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 our incurring losses.

The success of our operations is materially 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.

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, CIS, 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;

	•	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.

Certain of our contracts are subject to cancellation by our customers without penalty 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, 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. The cancellation or renegotiation of a number of our drilling contracts could materially reduce our revenue and profitability.

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 would adversely affect us. In 2009, our two largest customers, BP and ExxonMobil (including subsidiaries and joint ventures) accounted for approximately 26 percent and 15 percent of our total revenues, respectively. Our ten most significant customers collectively accounted for approximately 75 percent of our total revenues in 2009. Our results of operations could be adversely affected if any of our major customers terminate their contracts with us, fail to renew our existing contracts or refuse to award new contracts to us.

Contract drilling and the rental tools business are highly competitive and cyclical, with intense price competition.

The contract drilling and rental tools markets are highly competitive and although 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 tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company and which may materially 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 the markets 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 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 utilized, 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 operations could be adversely affected by terrorism, war, civil disturbances, political instability and similar events.

We currently have operations in 11 countries, including Netherlands, Singapore and the United States. 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. 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 also subject to governmental regulation and other risks.

We derive a significant portion of our revenues from our international operations. In 2009, we derived approximately 50 percent of our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, among others:


	•	inconsistency of foreign laws and governmental regulation;

	•	expropriation, confiscatory taxation and nationalization of our assets;

	•	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;

	•	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.

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 regulationsand/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.

A significant 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.

Our international operations are also subject to disruption due to risks associated with worldwide health concerns. In particular, although we have no evidence to believe this will occur, it is possible that concerns due to the transmission of illness (viral, bacterial or parasitic) could result in cancellations or delays in international flightsand/or the quarantine of drilling crews in foreign locations, which could materially impair our international operations and consequently have an adverse effect on our business and financial results for the operations that are affected.

Inconsistent application of foreign tax and other laws may adversely affect our operations.

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.

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 dully 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.

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 our rigs, our shore bases and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until 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 worsen 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 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.”

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 13, “Commitments and Contingencies,” in Item 8 of thisForm 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, the Company 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 the Company’s 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 the Company’s use of customs agents in certain countries in which the Company currently operates 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 has 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 the Company does business through a joint venture relationship in Kazakhstan. We are currently engaged in efforts to evaluate and implement alternatives to restructure or end the relationship with the subcontractor. At this point, we are unable to predict the outcome of our restructuring efforts or whether termination will result, either of which could negatively impact some of our operations in Kazakhstan and potentially have a material adverse impact on our business, results of operations, financial condition and liquidity.

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.

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 have 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 the Company 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.

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 thisForm 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.

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 9.625% Senior Notes upon a change of control.

Upon the occurrence of specific change of control events affecting us, the holders of our 9.625% 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 9.625% 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. Any credit facility in place at the time of a repurchase or conversion of the notes may also define as a default thereunder the events requiring repurchase or cash payment upon conversion of the notes or otherwise limit our ability to use borrowings 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.

The indenture for our 9.625% 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 9.625% 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 in respect of the related indebtedness. If a default were to occur, the holders of our 9.625% 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

ThisForm 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 thisForm 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;


	•	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 thisForm 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 conditionsand/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;


	•	unanticipated cancellation of contracts by operators;

	•	breakdown of equipment;

	•	other operational problems including delays instart-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 thisForm 10-K and our other reports and filings with the SEC.

Each forward-looking statement speaks only as of the date of thisForm 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 thisForm 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.

Land Rigs — International

The following table shows, as of December 31, 2009, the locations and drilling depth ratings of our 28 land rigs available for service. 18 of these rigs were under contract and ten more available for service as of December 31, 2009.


	Drilling Depth Rating in Feet
	10,000		10,000		Over
Region	or Less		25,000		25,000		Total

Asia Pacific		1		7		—		8
CIS/Africa Middle East		—		7		3		10
Americas		—		4		5		9
Unassigned		—		1		—		1

Total		1		19		8		28

Barge Rigs

The following table sets forth information regarding our two international deep drilling barges as of December 31, 2009. One rig was under contract and one was available for service as of December 31, 2009.

Year Built

Maximum

or Last

Drilling

International

Horsepower

Refurbished

Depth (Feet)

Caspian Sea:

Rig No. 257

3,000

1999

30,000

Mexico:

Rig No. 53 B

1,600

2004

20,000

The following table sets forth information regarding our 13 deep and intermediate depth drilling barge rigs located in the GOM as of December 31, 2009. Five of these barge rigs were under contract and eight were available for service as of December 31, 2009.


			Year Built		Maximum
			or Last		Drilling
U.S.	Horsepower		Refurbished		Depth (Feet)

Deep drilling:
Rig No. 12 B		1,500		2006		18,000
Rig No. 15 B		1,000		2007		15,000
Rig No. 50 B		2,000		2006		20,000
Rig No. 51 B		2,000		2008		20,000
Rig No. 54 B		2,000		2006		25,000
Rig No. 55 B		2,000		2001		25,000
Rig No. 56 B		2,000		2005		25,000
Rig No. 72 B		3,000		2005		30,000
Rig No. 76 B		3,000		2009		30,000
Rig No. 77 B		3,000		2006		30,000
Intermediate drilling:
Rig No. 8 B		1,000		2007		14,000
Rig No. 20 B		1,000		2005		13,000
Rig No. 21 B		1,200		2007		14,000

The following table presents our utilization rates and rigs available for service for the years ended December 31, 2009 and 2008.


	Year Ended December 31,
	2009			2008

International Land Rig Data
Rigs available for service(1) :		29.0			28.0
Utilization rate of rigs available for service(2):		67	%		79	%
Barge Rig Data
International barge drilling:
Rigs available for service(1)		2.0			2.0
Utilization rate of rigs available for service(2)		74	%		100	%
U.S. barge deep drilling:
Rigs available for service(1)		10.0			10.0
Utilization rate of rigs available for service(2)		41	%		85	%
U.S. barge intermediate drilling:
Rigs available for service(1)		3.0			3.0
Utilization rate of rigs available for service(2)		25	%		74	%
U.S. barge workover and shallow drilling:
Rigs available for service(1)		2.0			2.0
Utilization rate of rigs available for service(2)		20	%		41	%


(1)		The number of 100 percent-owned 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.


ITEM 3.	*LEGAL PROCEEDINGS*

For information on Legal Proceedings, see Note 13, Commitments and Contingencies, in the notes to the consolidated financial statements included in Item 8 of this annual report onForm 10-K, which information is incorporated herein by reference.


ITEM 4.	*RESERVED*

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.” At the close of business on December 31, 2009, there were 1,872 holders of record of Parker Drilling common stock. The following table sets forth the high and low closing sales prices per share of Parker Drilling’s common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:


	2009				2008
Quarter	High		Low		High		Low

First	$	3.34	$	1.28	$	7.82	$	5.53
Second		5.30		1.90		10.17		6.69
Third		5.71		3.55		10.18		7.77
Fourth		6.39		4.30		7.81		2.46

Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholders of record. As of January 29, 2010, our common stock was held by 1,862 holders of record and an estimated 24,729 beneficial owners as of February 9, 2010.

Restrictions contained in Parker Drilling’s existing credit agreement and the indenture for the 9.625% Senior Notes restrict the payment of dividends. We have no present intention to pay dividends on our common stock in the foreseeable future.

Unregistered Sales of Equity Securities and Use of Proceeds

When restricted stock awarded by Parker Drilling 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 below:


	Issuer Purchases of Equity Securities
					Total Number of
					Shares Purchased as		Maximum Number of
	Total Number				Part of Publicly		Shares That May yet
	of Shares		Average Price		Announced Plan or		Be Purchased Under
Period	Purchased		Paid per Share		Program		the Plan or Program

October 1-31, 2009		441	$	5.29		—		N/A
November 1-30, 2009		441	$	5.25		—		N/A
December 1-31, 2009		132	$	4.63		—		N/A

Total		1,014	$	5.06		—		N/A

These were the only repurchases of equity securities made by us during the three months ended December 31, 2009. We do not have a stock repurchase program.


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, 2009. 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 thisForm 10-K.


	Year Ended December 31,
	2009(1)			2008(1)(2)			2007(1)			2006(3)			2005(4)
	(Dollars in thousands, except per share amounts)

Income Statement Data
Total revenues	$	752,910		$	829,842		$	654,573		$	586,435		$	531,662
Total operating income		39,322			59,180			190,983			143,326			115,123
Equity in loss of unconsolidated joint venture, net of tax		—			(1,105	)		(27,101	)		—			—
Other expense		(29,495	)		(28,405	)		(24,141	)		(25,891	)		(44,895	)
Income tax (expense) benefit		560			6,942			36,895			(36,409	)		28,584
Income from continuing operations		9,267			22,728			102,846			81,026			98,812
Net income		9,267			22,728			102,846			81,026			98,883
Basic earnings per share:
Income from continuing operations	$	0.08		$	0.20		$	0.94		$	0.76		$	1.03
Net income	$	0.08		$	0.20		$	0.94		$	0.76		$	1.03
Diluted earnings per share:
Income from continuing operations	$	0.08		$	0.20		$	0.93		$	0.75		$	1.02
Net income	$	0.08		$	0.20		$	0.93		$	0.75		$	1.02
Balance Sheet Data
Cash and cash equivalents	$	108,803		$	172,298		$	60,124		$	92,203		$	60,176
Marketable securities		—			—			—			62,920			18,000
Property, plant and equipment, net		716,798			675,548			585,888			435,473			355,397
Assets held for sale		—			—			—			4,828			—
Total assets		1,243,086			1,205,720			1,067,173			901,301			801,620
Total long-term debt, including current portion of long-term debt		423,831			441,394			349,309			329,368			380,015
Stockholders’ equity		595,899			582,172			549,322			459,099			259,829


(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.” Such convertible debt instruments, by their terms, may be settled either wholly or partially in cash upon conversion. This new accounting guidance requires issuers of these convertible debt instruments to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate. Early adoption was not permitted and retroactive application to all periods presented was required. We reflected the impact of the new accounting guidance during each of the quarterly periods in our respective Quarterly Reports onForm 10-Q filed with the SEC during 2009. The amount reclassified upon implementation of $15.8 million to Additional Paid In Capital represents the equity component of the proceeds from the notes, calculated assuming a 7.25 percent non-convertible borrowing rate. The adoption of this accounting guidance impacted the historical accounting for the Company’s $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 thisForm 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.

(4)		The 2005 results reflect the reversal of a $71.5 million valuation allowance related to federal net operating loss carryforwards and other deferred tax assets as our evaluation of whether the existing tax uncertainty concluded a tax exposure likely no longer existed.


ITEM 7.	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*

OVERVIEW AND OUTLOOK

Summary

We delivered sound financial results in 2009 despite significant market instability and uncertainty. Our business balance and geographic diversity enabled us to mitigate the impact of the volatile conditions and difficult market forces that we faced. Guided by our long-term strategy, we continued to invest for future growth during this industry down-cycle and to position ourselves for stronger performance in the years ahead. In 2009 we captured a lead position in the U.S. barge drilling market, expanded the geographic presence of our rental tools operations and moved forward on our projects to begin drilling operations in Alaska. We entered 2010 in sound financial condition with sufficient resources to provide for the needs of our current operations and to fund our growth initiatives.

Overview

Parker Drilling’s revenues for the 2009 fourth quarter declined to $175.8 million, or by 17 percent, from 2008 fourth quarter revenues of $212.4 million. The Company’s 2009 fourth quarter gross margin declined to $43.0 million, or by 46 percent, from 2008 fourth quarter gross margin of $79.6 million, while gross margin as a percentage of revenues decreased to 24 percent in the 2009 fourth quarter from 38 percent in the 2008 fourth quarter.

International Drilling revenues declined 16 percent, to $72.7 million for the 2009 fourth quarter from $86.2 million for the 2008 fourth quarter, and gross margin declined 21 percent, to $21.9 million for the 2009 fourth quarter from $27.7 million in the 2008 fourth quarter. As a result, the segment’s gross margin as a percent of revenues declined to 30 percent from 32 percent. The revenue decline reflects a lower average fleet utilization, modestly higher average dayrates and the impact of Rig 257, our Caspian Sea barge rig, being in the shipyard for a scheduled overhaul and upgrade during the latter part of the 2009 fourth quarter. These effects were matched by lower operating costs throughout the segment. Average fleet utilization for the 2009 fourth quarter was 64 percent, compared with 87 percent for the 2008 fourth quarter. For the 2009 fourth quarter, the ten-rig Americas regional fleet operated at 80 percent utilization, the twelve-rig CIS/AME regional fleet operated at 68 percent utilization and the eight-rig Asia Pacific regional fleet operated at 46 percent utilization. Rig 259 was retired at the end of 2009, reducing the Company’s international fleet to 29 rigs and the CIS/AME regional fleet to eleven rigs.

U.S. Drilling revenues declined by 57 percent to $14.5 million for the 2009 fourth quarter from $33.6 million for the 2008 fourth quarter, while gross margin declined 91 percent, to $1.3 million from $14.6 million. The decline in revenues and gross margin are due to a sharp drop in rig activity and reduced average dayrates. The operation produced abetter-than-breakeven gross margin despite the significant downturn in industry demand. Average fleet utilization for the fourth quarter of 2009 was 52 percent, compared with 61 percent for the fourth quarter of 2008. The Company’s barge fleet dayrates averaged $19,300 for the fourth quarter of 2009, compared with $39,400 for the

fourth quarter of 2008. At December 31, 2009, our GOM barge rig fleet was reduced to 13 rigs with the retirements of workover barge rigs 6B and 16B.

Revenues for Rental Tools declined by 45 percent, to $25.1 million for the 2009 fourth quarter from $45.7 million for the 2008 fourth quarter, and the segment’s gross margin declined 52 percent to $13.8 million from $28.7 million. These reductions were primarily due to the decline in U.S. land and GOM shelf drilling activity and the impact of price discounting. This was partially offset by increased demand for workover equipment, growing coverage in the U.S. shale drilling areas and additional offshore deep drilling and international placements.

Project Management and Engineering Services revenues declined 27 percent, to $27.6 million for the 2009 fourth quarter from $37.9 million for the 2008 fourth quarter, and gross margin declined 33 percent to $5.4 million from $8.2 million. The prior year’s fourth quarter included revenues associated with the relocation and upgrade of the Yastreb rig for ENL on Sakhalin Island and operational revenues for ENL’s Orlan platform which has since moved to a warm-stack rate with reduced crew levels.

Construction Contract revenue increased to $35.8 million from $8.9 million while gross margin increased $0.1 million to $0.6 million from $0.5 million, representing progress made on the BP Liberty EPCI project.

Capital expenditures for the three month and twelve month periods ended December 31, 2009 totaled $33.2 million and $160.1 respectively. Major spending projects in 2009 including $62.2 million for the construction of Parker Drilling’s two new build arctic land rigs for Alaska and $36.8 million for tubular goods and other rental equipment.

Outlook

The steep market declines of late 2008 and early 2009 in certain of our markets have moderated and there are signs in some areas that improvements are underway. The utilization rate for the GOM barge drilling fleet has improved, though dayrates remain low. The domestic land rig count has recovered significantly, particularly in the shale plays where rental tool usage is more prevalent, leading to growing demand for rental tools and a lessening of price discounts. The number of international rig tenders has grown, yet commitments are slow to develop and pressure on dayrates remain. Our project engineering and project management opportunities are growing, indicating an expanded field for our unique capabilities and offering the prospect of significant future growth from this business segment

Though we are encouraged by the recent direction of activity in some of our markets, we remain cautious about the immediacy of a broad upturn and the near term impact on our financial performance. We believe we are well positioned to deliver profitable growth as the markets improve. Accordingly, we will continue to focus on cost management within our operations, improvements in delivering efficient performance to our customers and maintaining a safe environment for our employees.

We expect our international drilling business will continue to feel the effects of the 2009 downturn in E&P spending in our primary markets, including continued pressure on dayrates and gaps in the work schedule of certain rigs coming off contract during 2010. In addition, Rig 257, our Caspian Sea barge rig, will be on a reduced dayrate during its overhaul and upgrade period, which will continue into the second quarter.

Our U.S. Drilling business has experienced improved market conditions of late. Further improvement driven by higher natural gas prices or an increase in deep gas programs, may provide some upward momentum to the revenues and earnings of this business.

The rental tools business should benefit from its expanded international and offshore placements and rising demand in U.S. drilling, particularly the increases in the shale plays. A further reduction in price discounting could enhance results.

Based on our current project activity, we expect the higher revenues and earnings in 2010 for our project management business. The addition of the O&M for the BP-owned Liberty project is expected to account for much of this change. We are currently bidding on several projects that, should we be successful, could add to our backlog and revenue later this year.

The revenues and earnings for the Construction Contract segment will phase out as the BP-Liberty project transitions from EPCI to O&M, which is expected to occur in the second quarter of 2010. This project is expected to generate some revenue but relatively little earnings during that time.

Capital expenditures, funded primarily through operating cash flows and use of revolving credit facilities, for 2010 are projected to be approximately $150 to $175 million comprised of approximately $70 to $80 million for maintenance projects, including rental tool investments. Major project spending includes approximately $70 million to complete construction and delivery of the two Parker Drilling-owned drill rigs for Alaska and approximately $15 million for the overhaul and upgrade of Rig 257, our Arctic Class barge drilling rig operating in the Caspian Sea.

RESULTS OF OPERATIONS

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 consists 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.

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(1)	$	101,851		35	%	$	93,687		29	%
U.S. drilling gross margin excluding depreciation and amortization(1)		1,574		3	%		89,202		51	%
Rental tools gross margin excluding depreciation and amortization(1)		62,317		54	%		104,506		61	%
Project management and engineering services gross margin excluding depreciation and amortization(1)		23,646		22	%		18,470		17	%
Construction contract gross margin excluding depreciation and amortization(1)		8,132		4	%		2,597		5	%
Depreciation and amortization		(113,975	)				(116,956	)

Total operating gross margin(2)		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


(1)		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 gross margin, excluding depreciation and amortization, as a percent of revenues. The 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 gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such 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(2)	$	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(2)	$	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


(2)		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, further decreased by $93.1 million as a result of utilization decreasing from 77 percent 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, and the completion of the contract in China in 2009. These decreases were offset by higher revenues for our operations on the Yastreb rig in Sakhalin Island ($5.1 million) and Engineering Services ($18.1 million) 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 on which we earn a fixed fee during the rig move, upgrade and customer modification 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 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 the 2009 EPCI project is based on the percentage of completion of the contract in whichcosts-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 while being transported to shore. 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 are 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 13 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 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 13 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.

Year Ended December 31, 2008 Compared with Year Ended December 31, 2007

We recorded net income of $22.7 million for the year ended December 31, 2008 which included a goodwill write-off of $100.3 million, as compared to net income of $102.8 million for the year ended December 31, 2007. Operating gross margin was $191.5 million for the year ended December 31, 2008 which consists of increases in international drilling operations, rental tools, project management and engineering services and construction contract of $63.6 million offset by a decrease of $41.7 million in U.S. drilling and a $31.2 million increase in depreciation expense as compared to the year ended December 31, 2007.

In 2008, we began separate presentation of our project management and engineering services segment. We have begun to separately monitor this non-capital intensive segment as a focus of our long-term strategic growth plan. Prior to 2008, these results were included in the U.S. and International drilling segments, and as such, 2007 segment information has been recast to conform to the new presentation. We also created a new segment in 2008 to separately reflect results of our extended-reach rig construction contract.

The following is an analysis of our operating results for the comparable periods:


	Year Ended December 31,
	2008					2007
	(Dollars in thousands)

Revenues:
International drilling	$	325,096		39	%	$	213,566		33	%
U.S. drilling		173,633		21	%		225,263		34	%
Rental tools		171,554		21	%		138,031		21	%
Project management and engineering services		110,147		13	%		77,713		12	%
Construction contract		49,412		6	%		—

Total revenues	$	829,842		100	%	$	654,573		100	%

Operating gross margin:
International drilling gross margin excluding depreciation and amortization(1)	$	93,687		29	%	$	59,227		28	%
U.S. drilling gross margin excluding depreciation and amortization(1)		89,202		51	%		130,911		58	%
Rental tools gross margin excluding depreciation and amortization(1)		104,506		61	%		83,654		61	%
Project management and engineering services gross margin excluding depreciation and amortization(1)		18,470		17	%		12,732		16	%
Construction contract gross margin excluding depreciation and amortization(1)		2,597		5	%		—
Depreciation and amortization		(116,956	)				(85,803	)

Total operating gross margin(2)		191,506					200,721
General and administrative expense		(34,708	)				(24,708	)
Impairment of goodwill		(100,315	)
Provision for reduction in carrying value of certain assets		—					(1,462	)
Gain on disposition of assets, net		2,697					16,432

Total operating income	$	59,180				$	190,983


(1)		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 gross margin, excluding depreciation and amortization, as a percent of revenues. The gross margin amounts, excluding depreciation and amortization, and gross margin percentages should not be used as a substitute for those amounts reported under GAAP. However, we monitor our business segments based on several criteria, including gross margin. Management believes that this information is useful to our investors because it more


		accurately reflects cash generated by segment. Such 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, 2008
Operating gross margin(2)	$	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

Year Ended December 31, 2007
Operating gross margin(2)	$	31,046	$	97,679	$	59,264	$	12,732	$	—
Depreciation and amortization		28,181		33,232		24,390		—		—

Operating gross margin excluding depreciation and amortization	$	59,227	$	130,911	$	83,654	$	12,732	$	—


(2)		Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

International Drilling Segment

International drilling revenues increased $111.5 million to $325.1 million for the year ended December 31, 2008 as compared to the same period in 2007.

Revenues in Mexico, Algeria and Turkmenistan increased by $69.0 million, $11.1 million and $3.6 million, respectively, as there were minimal drilling operations in these countries during 2007. The increase in Mexico was partially attributable to dayrate increases for our barge rig operating in Mexico. Revenues in the CIS region increased by $63.7 million primarily due to a $19.5 million increase in the Karachaganak area of Kazakhstan as a result of the addition of Rigs 249 and 258 to existing operations of Rigs 107 and 216, an increase in the dayrate for our barge rig operating in the Caspian Sea and the above mentioned Turkmenistan revenues. These increases were partially offset by an increase of $22.2 million in revenues in Colombia as compared with 2007, due to lower utilization of our two rigs in Colombia in 2008.

In our Asia Pacific region, revenues decreased $8.2 million in 2008 due mainly to completion of our contract within Bangladesh for Rig 225 in March 2007 ($3.5 million) and 50 percent lower utilization in Papua New Guinea ($15.6 million). These increases were partially offset by a $4.8 million increase in New Zealand due to increased dayrates and operating days and a $6.2 million increase in our Indonesia operations.

International operating gross margin, excluding depreciation and amortization, increased $34.5 million to $93.7 million during 2008 compared with the year ended 2007, due primarily to favorable increases in our operations in Mexico ($25.5 million) and the CIS region ($21.4 million), offset by decreases in Colombia ($14.3 million) and our Asia Pacific region ($2.2 million). The increase in Mexico is attributable to five rigs operating the entire period in 2008 and two rigs commencing operations in February in 2008 as we were in the start up phase for these operations in the third quarter of 2007. In the CIS region, the primary driver was the increased dayrates for our barge rig operating in the Caspian Sea, increased utilization in the Karachaganak area of Kazakhstan and operation of Rig 230 in Turkmenistan were the main drivers of the increase. In Colombia, the completion of our contracts in late 2007 and late February 2008 were the cause of the decrease, although Rig 268 began a one year contract in mid-May 2008. Our Asia Pacific region decline of $2.2 million was a result of Rig 225 in Bangladesh not operating in 2008 as compared to 2007 and Papua New Guinea incurring lower utilization when compared to the same period of 2007, with these declines being partially offset by increases in our New Zealand and Indonesia operations.

U.S. Drilling Segment

Revenues for the U.S drilling segment decreased $51.6 million to $173.6 million for the year ended December 31, 2008 as compared to the year ended December 31, 2007. The decreased revenues were primarily due to a $40.3 million decrease for our barge drilling operations as average dayrates for our deep drilling barges fell approximately $4,500 per day. During 2007 we had two land rigs drilling in the U.S. that historically operated in our international land segment. These rigs contributed $11.3 million in U.S. revenues in 2007 as compared to no U.S. revenues in the same period for 2008, as the two rigs were relocated to our Mexico operations during 2007.

As a result of the above mentioned factors, gross margins, excluding depreciation and amortization, decreased $41.7 million to $89.2 million for the year ended December 31, 2008 as compared to the same period of 2007.

Rental Tools Segment

Rental tools revenues increased $33.5 million to $171.6 million during the year ended December 31, 2008 as compared to 2007. The increase was due primarily to an increase in rental revenues of $13.6 million at our Texarkana, Texas facility, $2.8 million at our New Iberia, Louisiana facility, $20.2 million from our newest location in Williston, North Dakota and $1.3 million from our Victoria, Texas location, partially offset by declines of $0.9 million from our Evanston, Wyoming facility, $1.7 million at our Odessa, Texas location and $1.8 million at our international operations. Revenues increased as a result of our expansion efforts in Texarkana, Texas and Williston, North Dakota.

The rental tools segment gross margins, excluding depreciation and amortization, increased $20.9 million to $104.5 million in 2008 as compared with 2007. The 2007 and 2008 expansion of Quail tools was completed as equipment had been delivered and Quail tools new facility in Texarkana, Texas opened in April 2007. The facility provides increased coverage of the Barnett, Fayetteville, Woodford and Haynesville shale areas in East Texas, Southwest Arkansas, Southeast Oklahoma and Northwest Louisiana.

Project Management and Engineering Services Segment

Revenues for this segment increased $32.4 million during 2008 as compared to 2007. This increase was the result of higher revenues for our operations in Sakhalin Island ($20.9 million) and Kuwait ($13.1 million). For Sakhalin operations, $9.1 million of the increase was due to higher dayrates and $11.8 million was due to reimbursable expenses on which we earn a fixed fee. For our Kuwait contract, $11.0 million of the increase was due to reimbursables and $2.1 million was due to additional services provided. These increases were partially offset by a decrease of $1.9 million in our Papua New Guinea project management contracts that ceased operations during 2007. Project management and engineering services gross margin for this segment increased $5.7 million in 2008 as compared with 2007. Labor rate increases effective in November 2008, which were retroactive to June 2008, positively impacted gross margin.

Construction Contract Segment

Revenues from the construction of the extended-reach drilling rig for use in the Alaskan Beaufort Sea were $49.4 million for 2008. This project is a cost plus fixed fee contract. Gross margin for the EPCI project was $2.6 million based on the percentage of completion of the contract in whichcosts-to-date compared to projected total costs are used to determine the percent complete (cost to cost method).

Other Financial Data

Gain on asset dispositions was $2.7 million in 2008, a decrease of $13.7 million from 2007 as a result of minor asset sales in 2008 as compared to gains of $16.4 million during the same period in 2007 as we sold two workover barge rigs in January 2007 for a recognized gain of $15.1 million. Interest expense for 2008 was $29.3 million, an increase of $2.1 million as compared to 2007. Interest income for 2008 decreased $5.1 million due to lower cash balances available for investments as compared to 2007. General and administration expense increased $10.0 million in 2008 as compared with 2007, due primarily to higher legal and professional fees associated with the ongoing

DOJ and SEC investigations into the customs agent discussed in Note 13 in the notes to the consolidated financial statements. These fees included upgrades to our compliance process and code of conduct.

In 2004, we entered into twovariable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported themark-to-market change in the fair value of the interest rate derivatives in earnings. During 2008, we had no swaps outstanding and therefore reported no charge or benefit related to swaps, as compared to the year ended December 31, 2007 where we recognized a $0.7 million decrease in the fair value of the derivative positions. For additional information see Note 6 in the notes to the consolidated financial statements.

Income tax expense was $6.9 million for the year ended December 31, 2008, as compared to income tax expense of $36.9 million for the year ended December 31, 2007. 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 13 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, 2009, we had cash and cash equivalents of $108.8 million, a decrease of $63.5 million from December 31, 2008. The following table provides a summary for the last three years:


	2009			2008			2007
	(Dollars in thousands)

Operating Activities	$	110,872		$	220,318		$	74,276
Investing activities		(150,718	)		(196,607	)		(152,889	)
Financing activities		(23,649	)		88,463			46,534
Net change in cash and cash equivalents		(63,495	)		112,174			(32,079	)

Operating Activities

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.

Cash flows from operating activities were $220.3 million for 2008 compared to $74.3 million for 2007. The increase in cash provided from operating activities is due to decreased working capital requirements and the net effect of a decrease to net income. Lower working capital requirements of $118.8 million were principally driven by a smaller increase in accounts receivable, lower accrued taxes and higher accrued liabilities compared to changes in 2007. Depreciation in 2008 increased to $117.0 million compared to $85.8 million in 2007 due to additional rigs being placed into service and major upgrades to existing rigs. All of our remaining goodwill, $100.3 million, was impaired in 2008 compared to no impairment in 2007.

Investing Activities

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, and $4.0 million relating to the settlement of a claim involving Barge Rig 57.

Cash flows used in investing activities were $196.6 million for 2008. Our primary use of cash was $197.1 million for capital expenditures and a $5.0 million investment in our Saudi joint venture, which was sold in April 2008. Major capital expenditures for the period included $58.3 million on the construction of two new Alaska rigs, $41.5 million for tubulars and other rental tools for Quail Tools and $31.2 million on construction of new international land rigs. Sources of cash included $5.5 million of proceeds from assets sales and insurance proceeds.

Our estimated expenditures for 2010 will primarily be directed to our two new Alaska rigs as well as 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 2010, though there can be no assurance that we will continue to generate cash flows at current 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 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.

Cash flows from financing activities were $88.5 million for 2008. Our primary sources of cash included a net drawdown on our credit facilities of $88.0 million and proceeds of $2.0 million from stock options exercised, offset by a payment of $1.8 million for debt issuance costs relating to our 2008 Credit Facility.

2008 Credit Facility

On May 15, 2008 we entered into a new Credit Agreement (as amended “the 2008 Credit Facility”) with a five year senior secured $80.0 million revolving credit facility (“Revolving Credit Facility) and a senior secured term loan facility (“Term Loan Facility”) of up to $50.0 million. Our obligations under the 2008 Credit Facility are guaranteed by substantially all of our domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed a guaranty. The obligations under the 2008 Credit Facility are secured by a pledge of the stock of all of the subsidiary guarantors, certain immaterial domestic subsidiaries and first-tier foreign subsidiaries, all receivables of the Company and the subsidiary guarantors, a naval mortgage on certain eligible barge drilling rigs owned by a subsidiary guarantor and the inventory and equipment of the Quail Tools, L.P., a subsidiary guarantor, and other tangible and intangible assets of the Company and its subsidiaries. The 2008 Credit Facility contains customary affirmative and negative covenants regarding ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. As of December 31, 2009 our Consolidated Leverage Ratio was 2.67 to 1 compared to the maximum permitted 4.00 to 1; our Consolidated Interest Coverage Ratio was 5.57 to 1 compared to the minimum permitted 2.50 to 1 and our Consolidated Senior Secured Leverage Ratio was 0.52 to 1 compared to the maximum permitted 1.50 to 1. We do not currently anticipate triggering any of these covenants during 2010.

The 2008 Credit Facility is available for general corporate purposes and to fund reimbursement obligations under letters of credit the banks issue on our behalf pursuant to this facility. Revolving loans are available under the 2008 Credit Facility subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and eligible rental equipment of the Company and its subsidiary guarantors. As of December 31, 2009, there were $12.7 million in letters of credit outstanding, $44.0 million outstanding on the Term Loan Facility and $42.0 million outstanding on the Revolving Credit Facility. The Term Loan began amortizing on September 30, 2009 at equal installments of $3.0 million per quarter. As of December 31, 2009, the amount drawn represents 68 percent of the capacity of the Revolving Credit Facility. On January 30, 2009, Lehman Commercial Paper, Inc., one of the lenders under the 2008 Credit Facility, assigned its obligations to Trustmark

National Bank. We expect to use the drawn amounts over the next twelve months to fund construction of two new rigs for work in Alaska. Although the economic downturn may affect certain customers’ ability to pay, the Company anticipates it has sufficient liquidity to meet its expected capital expenditures and manage any delays in collection of receivables.

2.125% Convertible Senior Notes

As discussed in Note 1 to our consolidated financial statements, our consolidated financial statements as of and for the years ended December 31, 2008 and 2007 have been adjusted to account for the retrospective application related to newly adopted accounting guidance in regards toAccounting 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. The $15.8 million reclassified to Additional Paid-In Capital supported adjustments to interest expense, deferred income taxes and long-term debt as discussed further in the notes to consolidated financial statements.

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.

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, the Company can either settle entirely in shares of common stock or a combination of cash and shares of common stock, solely at our option. The Company’s 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 reduced 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 shares of our cash and 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, 2009, none of the conditions allowing holders of the Senior Notes to convert had been met.

Concurrently with the issuance of the Notes, the Company purchased a convertible note hedge (the “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 the Company’s 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 issueand/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 the Company’s outstanding shares. The warrants allow the Company 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 $31.48 million for the call options, and we 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 Notes remain outstanding and 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 are classified in stockholders’ equity and are solely indexed to our own common stock, they are not accounted for as derivatives.

Debt issuance costs 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 (the “Senior Floating Rate Notes”), to pay the net cost of hedge and warrant transactions, and for general corporate purposes.

On September 27, 2007, we redeemed $100.0 million face value of our Senior Floating Rate Notes at the redemption price of 101.0 percent. A portion of the proceeds from the sale of our Convertible Senior Notes was used to fund the redemption.

2007 Credit Facility

On September 20, 2007, we replaced our existing $40.0 million Credit Agreement with a new $60.0 million Amended and Restated Credit Agreement (“2007 Credit Facility”) which would have expired in September 2012. The 2007 Credit Facility, which was replaced by the 2008 facility, was secured by rental tools equipment, accounts receivable and the stock of substantially all of our domestic subsidiaries, other than domestic subsidiaries owned by a foreign subsidiary, and contains customary affirmative and negative covenants such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.

Other Liquidity

Our principal amount of long-term debt, including current portion, was $423.8 million as of December 31, 2009, which consists of:


	•	$125.0 million aggregate principal amount of 2.125% Convertible Senior Notes due July 15, 2012, less an associated $14.6 million in unamortized debt discount;

	•	$225.0 million aggregate principal amount of 9.625% Senior Notes, due October 1, 2013 plus an associated $2.4 million in unamortized debt premium; and

	•	$86.0 million drawn against our 2008 Credit Facility, including $42.0 million under our Revolving Credit Facility and $44.0 million under our Term Loan Facility, $12.0 million of which is classified as current.

As of December 31, 2009, we had approximately $134.1 million of liquidity, which consisted of $108.8 million of cash and cash equivalents on hand and $25.3 million of availability under the 2008 Credit Facility. We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements nor guarantees of third-party financial obligations. We have no energy, commodity, foreign currency or interest rate derivative contracts at December 31, 2009.

The following table summarizes our future contractual cash obligations as of December 31, 2009:


	Payment Due by Period
			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)	$	394,000	$	12,000	$	149,000	$	233,000	$	—
Long-term debt — interest(1)		95,251		26,976		51,464		16,811		—
Operating leases(2)		25,062		6,438		5,394		3,328		9,902
Purchase commitments(3)		68,716		68,716		—		—		—

Total contractual obligations	$	583,029	$	114,130	$	205,858	$	253,139	$	9,902

Commercial commitments:
Long-term debt —
Revolving credit facility(4)	$	42,000	$	—	$	—	$	42,000	$	—
Standby letters of credit(4)		12,732		12,732		—		—		—

Total commercial commitments	$	54,732	$	12,732	$	—	$	42,000	$	—


(1)		Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes and the 2.125% Convertible Senior Notes. The remaining unamortized premium of $2.4 million and unamortized discount of $14.6 million are 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, 2009, related to rig upgrade projects and new rig construction.

(4)		We have an $80.0 million revolving credit facility. As of December 31, 2009, $42.0 million has been drawn down and $12.7 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $25.3 million of availability. The revolving credit facility expires May 14, 2013.

We used derivative instruments to manage risks associated with interest rate fluctuations in connection with our $100.0 million Senior Floating Rate Notes which were fully redeemed on September 27, 2007. These derivative instruments, which consisted ofvariable-to-fixed interest rate swaps, did not meet the criteria for applying hedge accounting and were therefore not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps was recognized in earnings.

On July 17, 2007, we terminated one swap scheduled to expire on September 2, 2008, and received $0.7 million. On September 4, 2007, our one remaining swap expired.

OTHER MATTERS

Business Risks

Internationally, we specialize in drilling geologically challenging wells in locations that are difficult to access and can involve harsh environmental conditions. Our international services are primarily utilized by major and national oil companies and integrated service providers in the exploration and development of reserves of oil and gas. In the United States, we primarily drill in the transition zones of the GOM for major and independent oil and gas companies. Business activity is primarily dependent on the exploration and development activities of the companies that make up our customer base. See Item 1A, Risk Factors, for a discussion of risks related to our business.

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 are believed 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, assumptionsand/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 and when step one undiscounted cash flow analysis failed.

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 market in the GOM, we tested our long-lived assets for impairment as of December 31, 2009 and determined that three of our rigs; two rigs in our U.S. Drilling segment and one in our International Drilling segment, required reductions of $0.4 million and $1.4 million, respectively in their net book value to salvage value based upon the our evaluation of future marketability, future cash infusions to maintain the equipment and evaluation of current market conditions affecting overall utilization of equipment in the regions in which we currently participate.

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.

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.

On January 1, 2007, we adopted 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. For meterage contracts, which are rare, we recognize the revenues and expenses upon completion of the well. 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 thecost-to-cost method.

Recent Accounting Pronouncements

noncontrolling interest be shown separately on the face of the statement of operations. The update also changes accounting for losses attributable to noncontrolling interests. Our adoption did not have a material effect on our consolidated balance sheet, statements of operations or cash flows.

Fair Value Measurements and Disclosures — Effective January 1, 2008, we adopted the accounting standards update related to fair value measurement of financial instruments that defined fair value, thereby offering a single source of guidance for the application of fair value measurement, established a framework for measuring fair value that contains a three-level hierarchy for the inputs to valuation techniques, and required enhanced disclosures about fair value measurements. Our adoption did not have a material effect on our consolidated balance sheet, statements of operations or cash flows.

Effective January 1, 2009, we adopted the remaining provisions of the accounting standards update for fair value measurement of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. Our adoption did not have a material effect on our consolidated balance sheet, statements of operations or cash flows.

Effective April 1, 2009, we adopted the accounting standards update related to measuring fair value when the volume and level of activity for the assets or liability have significantly decreased and identifying transactions that are not orderly, which provided additional guidance for estimating fair value when there is no active market or where the activity represents distressed sales on an interim and annual reporting basis. Our adoption did not have a material effect on our consolidated balance sheet, statements of operations or cash flows.

Subsequent Events — Effective for events occurring subsequent to June 30, 2009, we adopted the accounting standards update regarding subsequent events, which established the period after the balance sheet date during which management should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Our adoption did not have a material impact on the disclosures contained within our notes to consolidated financial statements.


ITEM 7A.	*QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK*

Foreign Exchange Risk

Our international operations expose us to foreign exchange risk. There are a variety of techniques to minimize the exposure to foreign exchange risk, including customer contract payment terms and the possible use of foreign exchange derivative instruments. Our primary foreign exchange 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 exchange 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 exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases, may be used to mitigate foreign currency risk. A foreign exchange 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, 2009, we had no open foreign exchange 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 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 $225.0 million principal amount of 9.625% Senior Notes due 2013, based on quoted market prices, was $231.2 million at December 31, 2009. The estimated fair value of our $125.0 million principal amount of 2.125% Convertible Senior Notes due 2012 was $113.1 million on December 31, 2009. A hypothetical 100 basis point increase in interest rates relative to market interest rates at December 31, 2009 would decrease the fair market value of our long-term debt at December 31, 2009 by approximately $22.3 million for the 9.625% Senior Notes and $33.8 million for the 2.125% Convertible Senior Notes.

In 2004, we entered into twovariable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported themark-to-market change in the fair value of the interest rate derivatives in earnings. For the year ended December 31, 2007, we recognized a $0.7 million decrease in the fair value of the derivative positions. On July 17, 2007, we terminated one swap scheduled to expire in September 2008 and received $0.7 million. The second swap was not renewed and expired on September 4, 2007.


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, 2009 and 2008, 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, 2009. 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, 2009. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control — Integrated Frameworkissued 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, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also in our opinion, Parker Drilling Company and

subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in note 1 to the consolidated financial statements, the Company has changed its method of accounting for convertible debt instruments in 2008 and 2007 due to the adoption of new accounting for convertible debt instruments.

/s/ KPMG LLP

Houston, Texas

March 3, 2010

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS


	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands, except per share data)

Revenues:
International drilling	$	293,337		$	325,096		$	213,566
U.S. drilling		49,628			173,633			225,263
Rental tools		115,057			171,554			138,031
Project management and engineering services		109,445			110,147			77,713
Construction contract		185,443			49,412			—

Total revenues		752,910			829,842			654,573

Operating expenses:
International drilling		191,486			231,409			154,339
U.S. drilling		48,054			84,431			94,352
Rental tools		52,740			67,048			54,377
Project management and engineering services		85,799			91,677			64,981
Construction contract		177,311			46,815			—
Depreciation and amortization		113,975			116,956			85,803

Total operating expenses		669,365			638,336			453,852

Total operating gross margin		83,545			191,506			200,721

General and administration expense		(45,483	)		(34,708	)		(24,708	)
Impairment of goodwill		—			(100,315	)		—
Provision for reduction in carrying value of certain assets		(4,646	)		—			(1,462	)
Gain on disposition of assets, net		5,906			2,697			16,432

Total operating income		39,322			59,180			190,983

Other income and (expense):
Interest expense		(29,450	)		(29,266	)		(27,217	)
Change in fair value of derivative positions		—			—			(671	)
Interest income		1,041			1,405			6,478
Loss on extinguishment of debt		—			—			(2,396	)
Equity in loss of unconsolidated joint venture, net of taxes		—			(1,105	)		(27,101	)
Minority interest		—			—			(1,000	)
Other		(1,086	)		(544	)		665

Total other income and (expense)		(29,495	)		(29,510	)		(51,242	)

Income before income taxes		9,827			29,670			139,741

Income tax expense (benefit):
Current tax expense (benefit)		15,424			(1,539	)		17,602
Deferred tax expense (benefit)		(14,864	)		8,481			19,293

Total income tax expense		560			6,942			36,895

Net income	$	9,267		$	22,728		$	102,846

Basic earnings per share:	$	0.08		$	0.20		$	0.94
Diluted earnings per share:	$	0.08		$	0.20		$	0.93
Number of common shares used in computing earnings per share:
Basic		113,000,555			111,400,396			109,542,364
Diluted		114,925,446			112,430,545			110,856,694

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
	2009			2008
	(Dollars in thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	108,803		$	172,298
Accounts and notes receivable, net of allowance for bad debts of $4,095 in 2009 and $3,169 in 2008		188,687			186,164
Rig materials and supplies		31,633			30,241
Deferred costs		4,531			7,804
Deferred income taxes		9,650			9,735
Other tax assets		37,818			40,924
Other current assets		62,407			26,125

Total current assets		443,529			473,291

Property, plant and equipment, at cost:
Drilling equipment		1,004,920			960,472
Rental tools		232,559			210,151
Buildings, land and improvements		30,548			27,340
Other		50,847			45,552
Construction in progress		211,889			144,721

		1,530,763			1,388,236
Less accumulated depreciation and amortization		813,965			712,688

Property, plant and equipment, net		716,798			675,548
Other assets:
Rig materials and supplies		9,291			7,219
Debt issuance costs		5,406			7,285
Deferred income taxes		55,749			22,956
Other assets		12,313			19,421

Total other assets		82,759			56,881

Total assets	$	1,243,086		$	1,205,720


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	12,000		$	6,000
Accounts payable		95,207			77,814
Accrued liabilities		72,703			62,584
Accrued income taxes		9,126			12,130

Total current liabilities		189,036			158,528

Long-term debt		411,831			435,394
Other long-term liabilities		30,246			21,396
Long-term deferred tax liability		16,074			8,230
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 116,239,097 shares (113,456,476 shares in 2008)		19,374			18,910
Capital in excess of par value		623,557			619,561
Accumulated deficit		(47,032	)		(56,299	)

Total stockholders’ equity		595,899			582,172

Total liabilities and stockholders’ equity	$	1,243,086		$	1,205,720

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS


	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	9,267		$	22,728		$	102,846
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		113,975			116,956			85,803
Impairment of goodwill		—			100,315			—
Loss on extinguishment of debt		—			—			1,396
Gain on disposition of assets		(5,906	)		(2,697	)		(16,432	)
Provision for reduction in carrying value of certain assets		4,646			—			1,462
Deferred tax expense		(14,864	)		8,481			19,293
Equity loss in unconsolidated joint venture		—			1,105			27,101
Expenses not requiring cash		11,626			15,333			13,502
Change in assets and liabilities:
Accounts and notes receivable		1,656			(14,958	)		(60,209	)
Rig materials and supplies		(3,464	)		(11,271	)		(4,945	)
Other current assets		(29,903	)		(15,737	)		(12,720	)
Accounts payable and accrued liabilities		29,735			(238	)		(19,728	)
Accrued income taxes		(13,004	)		(2,404	)		(48,998	)
Other assets		7,108			2,705			(14,095	)

Net cash provided by operating activities		110,872			220,318			74,276

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(160,054	)		(197,070	)		(242,098	)
Proceeds from the sale of assets		9,336			4,512			23,445
Proceeds from insurance claims		—			951			7,844
Investment in unconsolidated joint venture		—			(5,000	)		(5,000	)
Purchase of marketable securities		—			—			(101,075	)
Proceeds from sale of marketable securities		—			—			163,995

Net cash used in investing activities		(150,718	)		(196,607	)		(152,889	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from term note facility draw		—		$	50,000		$	125,000
Paydown on revolver credit facility		(20,000	)		(35,000	)		(100,000	)
Paydown on term note		(6,000	)		—			—
Proceeds from revolver draw		4,000			73,000			20,000
Purchase of call options		—			—			(31,475	)
Sale of common stock warrants		—			—			20,250
Payment of debt issuance costs		—			(1,846	)		(4,618	)
Proceeds from stock options exercised		199			1,969			15,455
Excess tax benefit (expense) from stock-based compensation		(1,848	)		340			1,922

Net cash provided by (used in) financing activities		(23,649	)		88,463			46,534

Net increase (decrease) in cash and cash equivalents		(63,495	)		112,174			(32,079	)
Cash and cash equivalents at beginning of year		172,298			60,124			92,203

Cash and cash equivalents at end of year	$	108,803		$	172,298		$	60,124

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	28,721		$	27,192		$	27,439
Income taxes	$	17,462		$	45,615		$	74,801

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


					Capital in
			Common		Excess of			Accumulated
	Shares		Stock		Par Value			Deficit
	(Dollars and shares in thousands)

Balances, December 31, 2006		109,150	$	18,220	$	568,253		$	(127,374	)
Activity in employees’ stock plans		2,766		433		14,931			—
Purchase of call options on Convertible Notes		—		—		(31,475	)		—
Sale of warrants on Convertible Notes		—		—		20,250			—
OID premium deferred tax asset reclass		—		—		12,149			—
Adoption of FIN 48		—		—		—			(54,499	)
Excess tax benefit from stock based compensation		—		—		1,922			—
Amortization of restricted stock plan compensation		—		—		7,836			—
Adjustment-Adoption of Convertible Debt (ASC470)		—		—		15,830			—
Net income (total comprehensive income of $102,846)		—		—		—			102,846

Balances, December 31, 2007		111,916	$	18,653	$	609,696		$	(79,027	)
Activity in employees’ stock plans		1,540		257		2,895			—
Excess tax benefit from stock based compensation		—		—		340			—
Amortization of restricted stock plan compensation		—		—		6,630			—
Net income (total comprehensive income of $22,728)		—		—		—			22,728

Balances, December 31, 2008		113,456	$	18,910	$	619,561		$	(56,299	)
Activity in employees’ stock plans		2,783		464		1,483			—
Tax Loss from stock based compensation		—		—		(1,848	)		—
Amortization of restricted stock plan compensation		—		—		4,361			—
Net income (total comprehensive income of $9,267)		—		—		—			9,267

Balances, December 31, 2009		116,239	$	19,374	$	623,557		$	(47,032	)

See accompanying notes to the consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


Note 1 —	Summary of Significant Accounting Policies

Nature of Operations —Parker Drilling Company (“Parker Drilling”) and its majority-owned subsidiaries (together with Parker Drilling, 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, 2009, the Company’s marketable rig fleet consisted of 13 barge drilling rigs and workover rigs, and 28 land rigs, which operated in the United States, South America, Middle East, CIS and Asia Pacific regions.

Application of Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)—The Company has adjusted the financial statements as of and for the three-years ended December 31, 2008, respectively, to reflect its adoption of the recently issued accounting guidance related to the accounting for convertible debt instruments that may be settled in cash upon conversion. The recently released accounting literature requires issuers to account separately for the liability and equity components of certain convertible debt instruments to adequately reflect the issuer’s nonconvertible debt features (unsecured debt) and borrowing rates when interest cost is recognized. The new accounting pronouncement requires separation of a component of that debt calculated as the difference between the original proceeds and the original note assuming a 7.25 percent non-convertible borrowing rate, with classification of that component in equity and the subsequent accretion of the resulting discount created on that debt to be recognized ratably (accretive) as part of interest expense in the Company’s consolidated statement of operations. The accounting pronouncement was effective January 1, 2009. The accounting guidance did not allow for early adoption. However, the Company’s adoption of the accounting treatment on January 1, 2009 required retrospective application of the new standard to the terms of the instruments for all periods presented. The adoption affects the Company’s historical accounting for its $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 following table summarizing the impact of these adjustments on the Company’s consolidated financial statements excluding certain amounts reclassified within net cash provided by operating activities in the Consolidated Statements of Cash Flow:


	Originally Reported						As Adjusted
Balance Sheet	December 31, 2008			Adjustments			December 31, 2008
	(Dollars in thousands)

ASSETS
Deferred income taxes	$	30,867		$	(7,911	)	$	22,956

Total assets	$	1,213,631					$	1,205,720


LIABILITIES AND STOCKHOLDERS’ EQUITY
Long-term debt	$	455,073		$	(19,679	)	$	435,394
Capital in excess of par		603,731			15,830			619,561
Accumulated deficit		(52,237	)		(4,062	)		(56,299	)

Total liabilities and stockholders’ equity	$	1,213,631					$	1,205,720

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Originally Reported						As Adjusted
	December 31, 2007			Adjustments			December 31, 2007

ASSETS
Deferred income taxes	$	40,121		$	(9,814	)	$	30,307

Total assets	$	1,076,987					$	1,067,173


LIABILITIES AND STOCKHOLDERS’ EQUITY
Long-term debt	$	353,721		$	(24,412	)	$	329,309
Capital in excess of par		593,866			15,830			609,696
Accumulated deficit		(77,795	)		(1,232	)		(79,027	)

Total liabilities and stockholders’ equity	$	1,076,987					$	1,067,173


	Originally Reported						As Adjusted
	Twelve Months Ended						Twelve Months Ended
Statement of Operations	December 31, 2008			Adjustments			December 31, 2008
	(Dollars in thousands)

Other expense:
Interest expense	$	(24,533	)	$	(4,733	)	$	(29,266	)
Income tax expense:
Deferred		10,384			(1,903	)		8,481

Net income	$	25,558					$	22,728


	Originally Reported						As Adjusted
	Twelve Months Ended						Twelve Months Ended
	December 31, 2007			Adjustments			December 31, 2007

Other expense:
Interest expense	$	(25,157	)	$	(2,060	)	$	(27,217	)
Income tax expense:
Deferred		20,121			(828	)		19,293

Net income	$	104,078					$	102,846

Consolidation— The consolidated financial statements include the accounts of the Company and subsidiaries in which the Company exercises significant control or has 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 the Parker Drilling’s interest in the entity does not meet the consolidation criteria described above.

Certain reclassifications have been made to prior period amounts to confirm with the current period presentation.

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Drilling Contracts and Rental Revenues— The Company recognizes revenues and expenses on dayrate contracts as drilling progresses. For meterage contracts, which are rare, the Company recognizes the revenues and expenses upon completion of the well. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months.

Construction Contract— Historically the Company has primarily constructed drilling rigs for its own use. In some instances, however, the Company enters into contracts to design, construct, deliver and commission a rig for a major customer. In 2008, the Company was awarded a cost reimbursable, fixed fee EPCI contract to construct, deliver and commission a rig for extended reach drilling work in Alaska. In 2006, the Company entered into a separate contract for the FEED of the rig. Total cost of the construction phase is currently expected to be approximately $245 million. The Company recognizes revenues received and costs incurred related to its construction contract on a gross basis and income for the related fees on a percentage of completion basis using thecost-to-cost method. Construction costs in excess of funds received from the customer are accumulated and reported as part of other current assets. At December 31, 2009, a net receivable (construction costs less progress payments) of $34.5 million is included in other current assets.

Reimbursable Costs— The Company recognizes reimbursements received forout-of-pocket expenses incurred as revenues and accounts forout-of-pocket expenses as direct operating costs. Such amounts totaled $41.1 million, $53.3 million and $25.4 million during the years ended December 31, 2009, 2008 and 2007, 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 the Company’s best estimate for losses that may occur resulting from disputed amounts and the inability of its customers to pay amounts owed. The Company determines the allowance based on historical write-off experience and information about specific customers. The Company reviews all past due balances over 90 days individually for collectibility.

Account balances are charged off against the allowance when the Company believes it is probable the receivable will not be recovered. The Company does not have any off-balance-sheet credit exposure related to customers.


	December 31,
	2009			2008
	(Dollars in thousands)

Trade	$	192,740		$	189,266
Employee(1)		42			67
Allowance for doubtful accounts(2)		(4,095	)		(3,169	)

Total receivables	$	188,687		$	186,164


(1)		Employee receivables related to cash advances for business expenses and travel.

(2)		Additional information on the allowance for doubtful accounts for the years ended December 31, 2009, 2008 and 2007 are reported on Schedule II — Valuation and Qualifying Accounts.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Property, Plant and Equipment— The Company provides 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		15 to 20 years
Barge drilling equipment		3 to 20 years
Drill pipe, rental tools and other		4 to 7 years
Buildings and improvements		10 to 20 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 services 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.

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 during 2009, 2008 and 2007 related to the construction of rigs totaled $6.0 million, $5.1 million and $6.2 million, respectively.

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, 2009 there was no existing goodwill. For further information see Note 3.

Rig Materials and Supplies— Since the Company’s 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. The Company classifies 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— The Company defers costs related to rig mobilization and amortizes such costs over the term of the related contract. The costs to be amortized within twelve months are classified as current.

Debt Issuance Costs— The Company typically capitalizes costs associated with debt financings and refinancing, and amortizes certain incurred costs over the term of the notes.

Income Taxes— 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. The Company adopted the accounting for uncertainty in income taxes as of January 1, 2007 in accordance with the published standards under generally accepted accounting principles (GAAP).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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. The Company generally does not require collateral on its trade receivables.

At December 31, 2009 and 2008, the Company had deposits in domestic banks in excess of federally insured limits of approximately $68.1 million and $126.3 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2009 and 2008 of $46.7 million and $50.0 million, respectively, which are not federally insured.

The Company’s customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2009, BP and ExxonMobil accounted for approximately 26 percent and 15 percent of total revenues, respectively.

Fair Value of Financial Instruments— The estimated fair value of the Company’s $225.0 million principal amount of 9.625% Senior Notes due 2013, based on quoted market prices, was $231.2 million at December 31, 2009. The estimated fair value of the Company’s $125.0 million principal amount of 2.125% Convertible Senior Notes due 2012 was $113.1 million on December 31, 2009. For cash, accounts receivable, rig supplies and materials and accounts payable, the Company believes carrying value approximates estimated fair value. See Note 4.

Stock-Based 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, 2009.

There were no options granted in during the three year period ended December 31, 2009. The tax expense realized for the tax deductions from option exercises and restricted stock vesting totaled $1.8 and $0.3 million for the years ended December 31, 2009 and 2008, respectively, which has been reported as a financing cash inflow in the consolidated condensed statement of cash flows. Cash received from option exercises for the years ended December 31, 2009 and 2008, respectively were $0.2 and $2.0 million. See Note 9 for additional information about the Company’s stock plans.


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 the Company had previously written-off the remaining net book value of the barge rig. Asset disposition in 2008 included the sale of Rig 206 in Indonesia, for which the Company recorded no gain or loss and miscellaneous equipment that resulted in a recognized gain of $2.7 million. Asset dispositions in 2007 consisted primarily of the sale of workover barge Rigs 9 and 26 for proceeds of approximately $20.5 million, resulting in a recognized gain of $15.1 million.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 3 —	Goodwill

As of December 31, 2008, the Company’s goodwill by reporting unit was: U.S. drilling barge rigs — $64.2 million and rental tools — $36.1 million, for a combined amount of $100.3 million. The goodwill was evaluated and primarily as a result of current equity market conditions in which the Company’s market capitalization was significantly under the book value of its assets and due to the uncertainty about financial markets’ return to normalcy, all of the Goodwill recorded on the Company’s books was written-down.


Note 4 —	Long-Term Debt

As discussed in Note 1, the Company’s 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.

The following table illustrates the Company’s current debt portfolio as of December 31, 2009:


	December 31,
	2009		2008
	(Dollars in thousands)

Convertible Senior Notes payable in July 2012 with interest at 2.125% payable semi-annually in January and July, net of unamortized discount of $14,596 at December 31, 2009 and $19,679 at December 31, 2008	$	110,404	$	105,321
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 and $3,073 at December 31, 2008. (Effective interest rate of 9.24% at December 31, 2009 and December 31, 2008)		227,427		228,073
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 3.48% at December 31, 2009)		44,000		50,000
Revolving Credit Facility with interest at prime, plus an applicable margin or LIBOR, plus an applicable margin. (Effective interest rate of 2.98% at December 31, 2009)		42,000		58,000

Total debt		423,831		441,394
Less current portion		12,000		6,000

Total long-term debt	$	411,831	$	435,394

The aggregate maturities of long-term debt are as follows:


	•	2010 — $12.0 million

	•	2011 — $12.0 million

	•	2012 — $137.0 million

	•	2013 — $275.0 million

Activity in 2009 —On January 30, 2009, Lehman Commercial Paper, Inc. assigned its obligations under the 2008 Credit Facility to Trustmark National Bank. Upon assignment, Trustmark National Bank fully funded Lehman Commercial Paper, Inc.’s commitment, including an additional $4.0 million that Lehman Commercial paper, Inc. did not fund in October 2008, therefore increasing our borrowings under the Revolving Credit Facility to $62.0 million at that time.

On June 3, 2009, we repaid $20.0 million of the Revolving Credit Facility, reducing the amount drawn to $42.0 million, which remains the balance at December 31, 2009.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our $50.0 million Term Loan began amortizing on September 30, 2009 at equal installments of $3.0 million per quarter resulting in an outstanding balance of $44.0 million on December 31, 2009.

At December 31, 2009, the Company had a $80.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2009, $12.7 million of availability has been reserved to support letters of credit that have been issued and $42.0 million was outstanding under the facility.

Activity in 2008 —On May 15, 2008, the Company entered into a new Credit Agreement (“2008 Credit Facility”) with a five year senior secured $80.0 million revolving credit facility (“Revolving Credit Facility) and a senior secured term loan facility (“Term Loan Facility”) of up to $50.0 million. The obligations of the Company under the 2008 Credit Facility are guaranteed by substantially all of Parker Drilling’s domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed a guaranty. The extensions of credit under the 2008 Credit Facility are secured by a pledge of the stock of all of the subsidiary guarantors, certain immaterial domestic subsidiaries and first-tier foreign subsidiaries, all receivables of the Company and the subsidiary guarantors, a naval mortgage on certain eligible barge drilling rigs owned by a subsidiary guarantor and the inventory and equipment of Quail Tools, L.P., a subsidiary guarantor, and other tangible and intangible assets of the Company and the subsidiaries. The 2008 Credit Facility contains customary affirmative and negative covenants such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. The 2008 Credit Facility replaced the 2007 Credit Facility described in “Activity in 2007” below.

The 2008 Credit Facility is available for general corporate purposes and to fund reimbursement obligations under letters of credit the banks issue on the Company’s behalf pursuant to this facility. Revolving loans are available under the 2008 Credit Facility subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and eligible rental equipment of the Company and its subsidiary guarantors. As of December 31, 2008, there were $12.8 million in letters of credit outstanding, $50.0 million outstanding under the Term Loan Facility and $58.0 million outstanding under the Revolving Credit Facility. The Term Loan will begin amortizing on September 30, 2009 at equal installments of $3.0 million per quarter. As of December 31, 2008, the amount drawn represented 94 percent of the capacity of the Revolving Credit Facility (which also reflected a $4.4 million reduction in available borrowing resulting from the bankruptcy filing of Lehman Brothers Holdings, Inc., the parent corporation of Lehman Commercial Paper, Inc., which had a $6.2 million lending commitment). The Company expects to use the additional drawn amounts over the next twelve months to fund construction of two new rigs to perform an anticipated five-year contract in Alaska based on an BP contract awarded August 2009.

Activity in 2007 —On July 5, 2007, the Company issued $125.0 million aggregate principal amount of 2.125 percent 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.

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 its Board of Directors, increase the conversion rate at its sole discretion for a period of at least 20 days.

	•	Notes Settlement Feature— Upon tender of the notes for conversion, the Company can either settle entirely in shares or a combination of cash and shares, solely at the Company’s option. The Company’s policy is to satisfy its conversion obligation for the notes in cash, rather than in common stock, for at least the aggregate principal amount of the notes. This reduced the resulting potential earnings dilution to only include any possible conversion premium, which would be the difference between the average price of the shares and the conversion price per share of common stock.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Contingent Conversion Feature— Note holders may only convert notes into shares 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 cash and 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, 2009, none of the conditions allowing holders of the Notes to convert had been met.

Concurrently with the issuance of the Convertible Notes, the Company purchased a convertible note hedge (the “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 the Company’s common shares. The convertible 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 issueand/or pay to the holders of the Notes upon conversion.

The Company paid a premium of approximately $31.48 million for the call options and received proceeds for a premium of approximately $20.25 million from 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 convertible Notes remain outstanding and the maturity date of the Notes.

The convertible notes are classified as a liability, of which a portion has been reclassified into equity as discussed in Note 1. Because the Company has 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 as outlined in accounting guidance related to accounting for derivative financial instruments indexed to, and potentially settled in, a company’s own stock, 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 are classified in stockholders’ equity and are solely indexed to the Company’s common stock, they are not accounted for as derivatives.

Debt issuance costs 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 the Company’s outstanding Senior Floating Rate notes, to pay the net cost of hedge and warrant transactions, and for general corporate purposes.

On September 27, 2007, the Company redeemed $100.0 million face value of its Senior Floating Rate Notes at the redemption price of 101.0 percent. A portion of the proceeds from the sale of the Company’s 2.125% Convertible Senior Notes was used to fund the redemption. All of the Company’s Senior Floating Rate Notes have been redeemed.


Note 5 —	Guarantor/Non-Guarantor Consolidating Condensed Financial Statements

Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling, its restricted subsidiaries that are guarantors of the Senior Notes, Senior Floating Rate Notes and Convertible Senior

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Notes (the “Notes”) and the restricted and unrestricted subsidiaries that are not guarantors of the Notes. The Notes are guaranteed by substantially all of the restricted subsidiaries of Parker Drilling. There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the company complies with the exception toRule 3-10(a)(1) ofRegulation S-X, set forth insub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100 percent by the parent company, all guarantees are full and unconditional and all guarantees are joint and several.

AralParker, Casuarina Limited (a wholly-owned captive insurance company), KDN Drilling Limited, Mallard Drilling of South America, Inc., Mallard Drilling of Venezuela, Inc., Parker Drilling Investment Company, Parker Drilling (Nigeria), Limited, Parker Drilling Company (Bolivia) S.A., Parker Drilling Company Kuwait Limited, Parker Drilling Company Limited (Bahamas), Parker Drilling Company of New Zealand Limited, Parker Drilling Company of Sakhalin, Parker Drilling de Mexico S. de R.L. de C.V., Parker Drilling International of New Zealand Limited, Parker Drilling Tengiz, Ltd., PD Servicios Integrales, S. de R.L. de C.V., PKD Sales Corporation, Parker SMNG Drilling Limited Liability Company (owned 50 percent by Parker Drilling Company International, LLC), Parker Drilling Kazakhstan, B.V., Parker Drilling AME Limited, Parker Drilling Asia Pacific, LLC, PD International Holdings C.V.,PD Dutch Holdings C.V., PD Selective Holdings C.V., PD Offshore Holdings C.V., Parker Drilling Netherlands B.V., Parker Drilling Dutch B.V., Parker Hungary Rig Holdings Limited Liability Company, Parker Drilling Spain Rig Services, S L, Parker 3Source, LLC, Parker 5272 LLC, Parker Central Europe Rig Holdings Limited Liability Company, Parker Cyprus Leasing Limited, Parker Cypress Ventures Limited, Parker Drilling International B.V., Parker Drilling Offshore B.V., Parker Drilling Offshore International, Inc., Parker Drilling Overseas B.V., Parker Drilling Russia B.V., Parker Drillsource, LLC, PD Labor Sourcing, Ltd., Mallard Argentine Holdings, Ltd., PD Personnel Services, Ltd., SaiPar Drilling Company B.V. (owned 50percent by Parker Drilling Dutch B.V.) and Parker Enex, LLC are all non-guarantor subsidiaries. The Company is providing consolidating condensed financial information of Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2009 and December 31, 2008 and for the years ended December 31, 2009, 2008 and 2007. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS


	Year Ended December 31, 2009
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

Total revenues	$	—		$	570,742		$	240,833		$	(58,665	)	$	752,910
Operating expenses		—			431,453			182,602			(58,665	)		555,390
Depreciation and amortization		—			83,728			30,247			—			113,975

Total operating gross margin		—			55,561			27,984			—			83,545

General and administration expense(1)		(180	)		(45,245	)		(58	)		—			(45,483	)
Provision for reduction in carrying value of certain assets		—			(4,646	)		—			—			(4,646	)
Gain on disposition of assets, net		—			5,572			334			—			5,906

Total operating income (loss)		(180	)		11,242			28,260			—			39,322

Other income and (expense):
Interest expense		(33,203	)		(46,679	)		(3,118	)		53,550			(29,450	)
Interest income		43,183			8,391			9,378			(59,911	)		1,041
Other		(3	)		818			(1,901	)		—			(1,086	)
Equity in net earnings of subsidiaries		(36,412	)		—			—			36,412			—

Total other income and (expense)		(26,435	)		(37,470	)		4,359			30,051			(29,495	)

Income (loss) before income taxes		(26,615	)		(26,228	)		32,619			30,051			9,827
Income tax expense (benefit):
Current		(17,407	)		25,032			7,799			—			15,424
Deferred		(18,475	)		3,112			499			—			(14,864	)

Total income tax expense (benefit)		(35,882	)		28,144			8,298			—			560

Net income (loss)	$	9,267		$	(54,372	)	$	24,321		$	30,051		$	9,267


(1)		All field operations general and administration expenses are included in operating expenses.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS


	Twelve Months Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in Thousands)

Total revenues	$	—		$	638,883		$	312,015		$	(121,056	)	$	829,842
Operating expenses		2			376,759			265,675			(121,056	)		521,380
Depreciation and amortization		—			85,617			31,339			—			116,956

Total operating gross margin		(2	)		176,507			15,001			—			191,506

General and administration expense(1)		(204	)		(34,466	)		(38	)		—			(34,708	)
Impairment of goodwill		—			(100,315	)		—			—			(100,315	)
Gain on disposition of assets, net		—			1,860			837			—			2,697

Total operating income (loss)		(206	)		43,586			15,800			—			59,180

Other income and (expense):
Interest expense		(33,990	)		(47,178	)		(308	)		52,210			(29,266	)
Changes in fair value of derivative positions		—			—			—			—			—
Interest income		42,575			7,577			3,463			(52,210	)		1,405
Equity in loss of unconsolidated joint venture, net of taxes		—			(1,105	)		—			—			(1,105	)
Other		(2	)		(776	)		234			—			(544	)
Equity in net earnings of subsidiaries		(8,037	)		—			—			8,037			—

Total other income and (expense)		546			(41,482	)		3,389			8,037			(29,510	)

Income (benefit) before income taxes		340			2,104			19,189			8,037			29,670
Income tax expense (benefit):
Current		(25,850	)		12,432			11,879			—			(1,539	)
Deferred		3,462			4,833			186			—			8,481

Total income tax expense (benefit)		(22,388	)		17,265			12,065			—			6,942

Net income (loss)	$	22,728		$	(15,161	)	$	7,124		$	8,037		$	22,728


(1)		All field operations general and administration expenses are included in operating expenses.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS


	Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

Revenues	$	—		$	573,164		$	136,319		$	(54,910	)	$	654,573
Operating expenses		1			311,867			111,091			(54,910	)		368,049
Depreciation and amortization		—			77,204			8,599			—			85,803

Operating gross margin		(1	)		184,093			16,629			—			200,721

General and administration expense(1)		(165	)		(24,485	)		(58	)		—			(24,708	)
Provision for reduction in carrying
value of certain assets		—			(1,462	)		—			—			(1,462	)
Gain (loss) on disposition of assets, net		—			16,448			(16	)		—			16,432

Total operating income (loss)		(166	)		174,594			16,555			—			190,983

Other income and (expense):
Interest expense		(31,978	)		(47,183	)		(551	)		52,495			(27,217	)
Changes in fair value of derivative positions		(671	)		—			—			—			(671	)
Interest income		47,435			11,878			(340	)		(52,495	)		6,478
Loss on extinguishment of debt		(2,396	)		—			—			—			(2,396	)
Equity in loss of unconsolidated joint venture, net of taxes		—			—			(27,101	)		—			(27,101	)
Minority interest		—			—			(1,000	)		—			(1,000	)
Other		9			618			44			(6	)		665
Equity in net earnings of subsidiaries		101,432			—			—			(101,432	)		—

Total other income and (expense)		113,831			(34,687	)		(28,948	)		(101,438	)		(51,242	)

Income (loss) before income taxes		113,665			139,907			(12,393	)		(101,438	)		139,741
Income tax expense (benefit):
Current		(4,237	)		16,217			5,622			—			17,602
Deferred		15,056			2,626			1,611			—			19,293

Income tax expense		10,819			18,843			7,233			—			36,895

Net income (loss)	$	102,846		$	121,064		$	(19,626	)	$	(101,438	)	$	102,846


(1)		All field operations general and administration expenses are included in operating expenses.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET


	December 31, 2009
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	58,189		$	3,683		$	46,931		$	—		$	108,803
Accounts and notes receivable, net		17,357			219,237			117,066			(164,973	)		188,687
Rig materials and supplies		—			10,914			20,719			—			31,633
Deferred costs		—			2,221			2,310			—			4,531
Deferred income taxes		9,650			—			—			—			9,650
Other tax assets		96,450			(57,534	)		(1,098	)		—			37,818
Other current assets		557			49,347			23,250			(10,747	)		62,407

Total current assets		182,203			227,868			209,178			(175,720	)		443,529

Property, plant and equipment, net		79			521,793			194,802			124			716,798
Investment in subsidiaries and intercompany advances		903,616			898,949			80,472			(1,883,037	)		—
Investment in and advances to unconsolidated joint venture		—			4,620			(4,620	)		—			—
Other noncurrent assets		56,658			20,905			13,296			(8,100	)		82,759

Total assets	$	1,142,556		$	1,674,135		$	493,128		$	(2,066,733	)	$	1,243,086


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	12,000		$	—		$	—		$	—		$	12,000
Accounts payable and accrued liabilities		50,583			387,246			95,797			(365,716	)		167,910
Accrued income taxes		1,069			2,372			5,685			—			9,126

Total current liabilities		63,652			389,618			101,482			(365,716	)		189,036

Long-term debt		411,831			—			—			—			411,831
Other long-term liabilities		9,692			14,646			6,127			(219	)		30,246
Long-term deferred tax liability		(1,098	)		13,178			3,994			—			16,074
Intercompany payables		62,583			586,636			42,003			(691,222	)		—
Contingencies		—			—			—			—			—
Stockholders’ equity:
Common stock		19,374			39,899			21,153			(61,052	)		19,374
Capital in excess of par value		623,554			997,082			256,395			(1,253,474	)		623,557
Retained earnings (accumulated deficit)		(47,032	)		(366,924	)		61,974			304,950			(47,032	)

Total stockholders’ equity		595,896			670,057			339,522			(1,009,576	)		595,899

Total liabilities and stockholders’ equity	$	1,142,556		$	1,674,135		$	493,128		$	(2,066,733	)	$	1,243,086

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET


	December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in Thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	111,324		$	9,741		$	51,233		$	—		$	172,298
Accounts and notes receivable, net		51,792			217,435			131,591			(214,654	)		186,164
Rig materials and supplies		—			11,518			18,723			—			30,241
Deferred costs		—			2,000			5,804			—			7,804
Deferred income taxes		9,735			—			—			—			9,735
Other tax assets		83,788			(41,008	)		(1,856	)		—			40,924
Other current assets		549			13,755			11,875			(54	)		26,125

Total current assets		257,188			213,441			217,370			(214,708	)		473,291

Property, plant and equipment, net		79			465,659			209,686			124			675,548
Investment in subsidiaries and intercompany advances		867,684			1,066,216			(88,992	)		(1,844,908	)		—
Investment in and advances to unconsolidated joint venture		—			4,620			(4,620	)		—			—
Other noncurrent assets		27,607			21,215			8,059			—			56,881

Total assets	$	1,152,558		$	1,771,151		$	341,503		$	(2,059,492	)	$	1,205,720


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	6,000		$	—		$	—		$	—		$	6,000
Accounts payable and accrued liabilities		53,859			337,464			100,305			(351,230	)		140,398
Accrued income taxes		540			4,861			6,729			—			12,130

Total current liabilities		60,399			342,325			107,034			(351,230	)		158,528

Long-term debt		435,394			—			—			—			435,394
Other long-term liabilities		10			14,351			7,035			—			21,396
Long-term deferred tax liability		—			1,237			6,993			—			8,230
Intercompany payables		74,583			583,027			71,299			(728,909	)		—
Contingencies		—			—			—			—			—
Stockholders’ equity:
Common stock		18,910			39,899			21,153			(61,052	)		18,910
Capital in excess of par value		619,561			1,045,727			141,112			(1,186,839	)		619,561
Retained earnings (accumulated deficit)		(56,299	)		(255,415	)		(13,123	)		268,538			(56,299	)

Total stockholders’ equity		582,172			830,211			149,142			(979,353	)		582,172

Total liabilities and stockholders’ equity	$	1,152,558		$	1,771,151		$	341,503		$	(2,059,492	)	$	1,205,720

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS


	Year Ended December 31, 2009
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

Cash flows from operating activities:
Net income (loss)	$	9,267		$	(54,373	)	$	24,322		$	30,051		$	9,267
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			83,728			30,247			—			113,975
Gain on disposition of assets		—			(5,572	)		(334	)		—			(5,906	)
Deferred tax expense (benefit)		(18,475	)		3,112			499			—			(14,864	)
Provision for reduction in carrying value of certain assets		—			4,646			—			—			4,646
Expenses not requiring cash		11,626			—			—			—			11,626
Equity in net earnings of subsidiaries		36,412			—			—			(36,412	)		—
Change in accounts receivable		34,435			(47,304	)		14,525			—			1,656
Change in other assets		(35,604	)		25,082			(15,737	)		—			(26,259	)
Change in liabilities		17,203			9,128			(9,600	)		—			16,731

Net cash provided by (used in) operating activities		54,864			18,447			43,922			(6,361	)		110,872

Cash flows from investing activities:
Capital expenditures		—			(144,184	)		(15,870	)		—			(160,054	)
Proceeds from the sale of assets		—			9,098			238			—			9,336
Intercompany dividend payments		—			—			(6,361	)		6,361			—

Net cash provided by (used in) investing activities		—			(135,086	)		(21,993	)		6,361			(150,718	)

Cash flows from financing activities:
Proceeds from draw on revolver credit facility		4,000			—			—			—			4,000
Paydown on revolver credit facility		(26,000	)		—			—			—			(26,000	)
Proceeds from stock options exercised		199			—			—			—			199
Excess tax cost from stock-based compensation		(1,848	)		—			—			—			(1,848	)
Intercompany advances, net		(84,350	)		110,582			(26,232	)		—			—

Net cash provided by (used in) financing activities		(107,999	)		110,582			(26,232	)		—			(23,649	)

Net increase (decrease) in cash and cash equivalents		(53,135	)		(6,057	)		(4,303	)		—			(63,495	)
Cash and cash equivalents at beginning of year		111,324			9,741			51,233			—			172,298

Cash and cash equivalents at end of period	$	58,189		$	3,683		$	46,931		$	—		$	108,803

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS


	Twelve months ending December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

Cash flows from operating activities:
Net income (loss)	$	22,728		$	(15,161	)	$	7,124		$	8,037		$	22,728
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			85,617			31,339			—			116,956
Impairment of goodwill		—			100,315			—			—			100,315
Amortization of debt issuance and premium		1,237			—			—			—			1,237
Gain on disposition of assets		—			(1,860	)		(837	)		—			(2,697	)
Deferred tax expense		3,462			4,833			186			—			8,481
Equity in loss of unconsolidated joint venture		—			1,105			—			—			1,105
Expenses not requiring cash		14,096			—			—			—			14,096
Equity in net earnings of subsidiaries		8,037			—			—			(8,037	)		—
Change in accounts receivable		27,895			9,550			(52,403	)		—			(14,958	)
Change in other assets		(36,459	)		16,044			(3,888	)		—			(24,303	)
Change in liabilities		13,013			(51,295	)		35,640			—			(2,642	)

Net cash provided by operating activities		54,009			149,148			17,161			—			220,318

Cash flows from investing activities:
Capital expenditures		—			(162,578	)		(34,492	)		—			(197,070	)
Proceeds from the sale of assets		—			1,449			3,063			—			4,512
Proceeds from insurance claims		—			—			951			—			951
Investment in unconsolidated joint venture		—			(5,000	)		—			—			(5,000	)

Net cash used in investing activities		—			(166,129	)		(30,478	)		—			(196,607	)

Cash flows from financing activities:
Proceeds from issuance of debt		50,000			—			—			—			50,000
Principal payments under debt obligations		(35,000	)		—			—			—			(35,000	)
Proceeds from revolver draw		73,000			—			—			—			73,000
Payment of debt issuance costs		(1,846	)		—			—			—			(1,846	)
Proceeds from stock options exercised		1,969			—			—			—			1,969
Excess tax benefit from stock-based compensation		340			—			—			—			340
Intercompany advances, net		(62,474	)		18,408			44,066			—			—

Net cash provided by financing activities		25,989			18,408			44,066			—			88,463

Net increase in cash and cash equivalents		79,998			1,427			30,749			—			112,174
Cash and cash equivalents at beginning of year		31,326			8,314			20,484			—			60,124

Cash and cash equivalents at end of year	$	111,324		$	9,741		$	51,233		$	—		$	172,298

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS


	Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
	(Unaudited)
	(Dollars in thousands)

Cash flows from operating activities:
Net income (loss)	$	102,846		$	121,064		$	(19,626	)	$	(101,438	)	$	102,846
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		—			77,204			8,599			—			85,803
Amortization of debt issuance and premium		845			—			—			—			845
Loss on extinguishment of debt		1,396			—			—			—			1,396
Gain/(loss) on disposition of assets		—			(16,448	)		16			—			(16,432	)
Deferred income tax expense		15,056			2,626			1,611			—			19,293
Equity in loss of unconsolidated joint venture								27,101			—			27,101
Provision for reduction in carrying value of certain assets		—			1,462			—			—			1,462
Expenses not requiring cash		13,247			(590	)		—			—			12,657
Equity in net earnings of subsidiaries		(101,432	)		—			—			101,432			—
Change in accounts receivable		(25,844	)		10,149			(44,514	)		—			(60,209	)
Change in other assets		(21,409	)		36,881			(47,232	)		—			(31,760	)
Change in liabilities		(24,119	)		(85,496	)		40,883			6			(68,726	)

Net cash provided by (used in) operating activities		(39,414	)		146,852			(33,162	)		—			74,276

Cash flows from investing activities:												��
Capital expenditures		—			(235,189	)		(6,909	)		—			(242,098	)
Proceeds from the sale of assets		54			22,865			526			—			23,445
Proceeds from insurance claims		—			7,844			—						7,844
Investment in unconslidated joint venture		—						(5,000	)					(5,000	)
Purchase of marketable securities		(101,075	)		—			—			—			(101,075	)
Proceeds from sale of marketable securities		161,995			2,000			—			—			163,995

Net cash provided by (used in) investing activities		60,974			(202,480	)		(11,383	)		—			(152,889	)

Cash flows from financing activities:
Proceeds from issuance of debt		125,000			—			—			—			125,000
Principal payments under debt obligations		(100,000	)		—			—			—			(100,000	)
Proceeds from draw on revolver credit facility		20,000			—			—			—			20,000
Purchase of call options		(31,475	)		—			—			—			(31,475	)
Proceeds from sale of common stock warrants		20,250			—			—			—			20,250
Payment of debt issuance costs		(4,618	)		—			—			—			(4,618	)
Proceeds from stock options exercised		15,455			—			—			—			15,455
Excess tax benefit from stock based compensation		1,922			—			—			—			1,922
Intercompany advances, net		(96,797	)		49,575			47,222			—			—

Net cash provided by (used in) financing activities		(50,263	)		49,575			47,222			—			46,534

Net increase (decrease) in cash and cash equivalents		(28,703	)		(6,053	)		2,677			—			(32,079	)
Cash and cash equivalents at beginning of year		60,029			14,367			17,807			—			92,203

Cash and cash equivalents at end of year	$	31,326		$	8,314		$	20,484		$	—		$	60,124

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Derivative Financial Instruments

The Company entered into twovariable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the $150.0 million Senior Floating Rate Notes. The first agreement, signed on August 18, 2004, fixed the interest rate on $50.0 million at 8.83 percent for a three-year period beginning September 1, 2006 and terminating September 2, 2009 and the second fixed the interest rate on an additional $50.0 million at 8.48 percent for the two-year period beginning September 1, 2006 and terminating September 4, 2008. In each case, an option to extend each swap for an additional two years at the same rate was given to the issuer, Bank of America, N.A.

The swap agreements did not qualify for hedge accounting and accordingly, the Company reported themark-to-market change in the fair value of the interest rate derivatives in earnings. For the year ended December 31, 2007, the Company recognized a $0.7 million decrease in the fair value of the derivative positions. On July 17, 2007, the Company terminated one swap scheduled to expire on September 2, 2008 and received $0.7 million. The second swap was not renewed and expired on September 4, 2007.


Note 7 —	Income Taxes

Income (loss) before income taxes is summarized below:


	Year Ended December 31,
	2009			2008			2007
	(Dollars in thousands)

United States	$	(62,265	)	$	(30,212	)	$	125,424
Foreign		72,092			59,882			14,317

	$	9,827		$	29,670		$	139,741

Income tax expense (benefit) is summarized as follows:


	Year Ended December 31,
	2009			2008			2007
	(Dollars in Thousands)

Current:
United States:
Federal	$	(4,541	)	$	(3,751	)	$	13,860
State		128			407			791
Foreign		19,837			1,805			2,951
Deferred:
United States:
Federal		(14,818	)		8,914			15,838
State		(1,793	)		(784	)		4,183
Foreign		1,747			351			(728	)

	$	560		$	6,942		$	36,895

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,
	2009						2008						2007
				% of Pre-Tax						% of Pre-Tax						% of Pre-Tax
	Amount			Income			Amount			Income			Amount			Income
	(Dollars in Thousands)

Computed Expected Tax Expense	$	3,439			35	%	$	10,384			35	%	$	48,909			35	%
Foreign Taxes		20,432			208	%		22,391			75	%		12,669			9	%
Tax Effect Different From Statutory Rates		(10,658	)		(108	)%		(4,449	)		(15	)%		8,916			6	%
State Taxes, net of federal benefit		(1,355	)		(14	)%		(180	)		(1	)%		4,973			4	%
Foreign Tax Credits		(14,152	)		(144	)%		(20,404	)		(69	)%		(16,020	)		(11	)%
Kazakhstan Tax Credits		—			—						—			(22,547	)		(16	)%
Kazakhstan FIN 48 Items		—			—			(13,002	)		(44	)%		(12,427	)		(9	)%
Change in Valuation Allowance		638			6	%		(1,835	)		(6	)%		5,764			4	%
Foreign Corporation Income		5,116			52	%		2,997			10	%		304			—
FIN 48 — Uncertain Tax Positions		1,184			12	%					—			7,807			6	%
FIN 48 — Foreign Tax Credits — Prior Years		1,798			18	%					—			—			—
State NOL		(165	)		(2	)%					—			—			—
Tax Benefit of Foreign Divestment		—			—			(3,456	)		(12	)%		—			—
Permanent Differences		2,893			29	%		3,189			11	%		(465	)		—
Prior Year Return to Provision Adjustments		(3,237	)		(33	)%					—						—
Foreign Tax Credits — Prior Years		(5,389	)		(55	)%					—			—			—
Other		16			—			(1,329	)		(4	)%		(988	)		(1	)%
Goodwill		—			—			12,636			43	%		—			—

Actual Tax Expense	$	560			6	%	$	6,942			23	%	$	36,895			27	%

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of the Company’s deferred tax assets and (liabilities) as of December 31, 2009 and 2008 are shown below:


	December 31,
	2009			2008
	(Dollars in thousands)

Deferred tax assets
Current deferred tax assets:
Reserves established against realization of certain assets	$	4,876		$	5,362
Accruals not currently deductible for tax purposes		4,774			4,373
Gross current deferred tax assets		9,650			9,735
Current deferred tax valuation allowance		—			0

Net current deferred tax assets		9,650			9,735

Non-current deferred tax assets:
Federal net operating loss carryforwards		4,288			0
State net operating loss carryforwards		6,291			4,273
Other state deferred tax asset, net		4,913			5,015
Foreign Tax Credits		14,152			0
Other long term liabilities		2,149			2,149
Deferred compensation		—			809
Note Hedge Interest		7,204			9,304
Percentage of Completion Construction Projects		17			491
Goodwill		3,483			5,810
FIN 48		11,245			5,162
Foreign tax local		6,232			0
Property, Plant and equipment		—			2,941
Other		969			(531	)
Rounding		—			0

Gross long-term deferred tax assets		60,943			35,423
Valuation Allowance		(5,194	)		(4,556	)

Net non-current deferred tax assets		55,749			30,867

Net deferred tax assets		65,399			40,602

Deferred tax liabilities:
Non-current deferred tax liabilities:
Property, Plant and equipment		(1,963	)		(4,507	)
Goodwill		—			0
Deferred tax impact of 481(a) adjustment related to FTCs		—			(4,645	)
Foreign tax local		(6,708	)		(342	)
Federal benefit of foreign tax		(1,032	)		(1,032	)
Convertible Debt — State		(1,023	)		(1,024	)
Convertible Debt — Federal		(5,109	)		(6,887	)
Deferred compensation		(239	)		0
Other		—			2,296

Net non-current deferred tax liabilities		(16,074	)		(16,141	)

Net deferred tax asset	$	49,325		$	24,461

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, the Company assesses the likelihood that its 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 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. The Company uses its judgment to determine the provision or benefit for income taxes, and any valuation allowance recorded against the deferred tax assets.

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, the Company had $124 million of gross state NOL carryforwards. For tax purposes, the state NOL carryforwards expire over a15-year period from December 31, 2010 through 2024 for which a $0.6 million state valuation allowance has been established. During 2009, the Company 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, the Company 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 the Company could realize the benefit in future periods.

The 2007 results reflect the establishment of valuation allowances related to NOL carryforwards and other deferred tax assets in the U.S. The valuation allowances were recorded as an offset to the Company’s deferred tax assets, relating to foreign tax credits and state NOL carryforwards. The Company recorded the valuation allowance based on management’s analysis which concluded that it was not more likely than not that the Company could realize the benefit of the foreign tax credit and state NOL carryforwards in future periods.

Effective January 1, 2007, the company adopted newly issued accounting guidance related to accounting for uncertainty in income taxes. This new accounting pronouncement prescribed 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, 2009	$	(11.7	)
Decreases related to prior year tax positions		0.0
Additions based on tax positions taken during the current period		(2.9	)
Lapse of statute		0.0

Balance at December 31, 2009	$	(14.6	)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In many cases, the Company’s 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, 2009:


Colombia		2007-present
Kazakhstan		2004-present
Mexico		2004-present
New Zealand		2004-present
Papua New Guinea		2003-present
Russia		2006-present
United States — Federal		1992-present

FIN 48 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions 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. At December 31, 2009, the Company had a liability for unrecognized tax benefits of $14.6 million (all of which, if recognized, would favorably affect the Company’s effective tax rate).

The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2008 and December 31, 2009 we had approximately $8.4 million and $9.6 million of accrued interest and penalties related to uncertain tax positions, respectively. The Company recognized an increase of $1 million of interest and an increase of $0.2 million of penalties on unrecognized tax benefits for the year ended December 31, 2009.


Note 8 —	Saudi Arabia Joint Venture

On April 9, 2008, a subsidiary of Parker Drilling executed an agreement (“Sale Agreement”) to sell its 50 percent share interest in Al-Rushaid Parker Drilling Co. Ltd. (“ARPD”) to an affiliate of the Al Rushaid subsidiary that owns the remaining 50 percent interest. The terms of the Sale Agreement provided for a $2.0 million payment to Parker Drilling’s subsidiary as consideration for the 50 percent share interest of the Parker Drilling subsidiary and partial repayment of investments and advances of the Parker Drilling subsidiary to ARPD, including a $5.0 million advance in January 2008. The Parker Drilling subsidiary received the $2.0 million on April 15, 2008 in full settlement of the Company’s investment in and advances to ARPD.

The Sale Agreement obligated the resulting Saudi shareholders to indemnify the Parker Drilling subsidiary and its affiliates from claims arising out of or related to the operations of ARPD, including the drilling contracts between ARPD and Saudi Aramco, ARPD’s bank loans and vendors providing goods or services to ARPD. The formal transfer of shares was approved by the Saudi Arabian authorities in July 2008. Equity investment in ARPD was zero at December 31, 2008 and 2009.

Parker Drilling’s subsidiary incurred $27.1 million in losses related to its 50 percent interest in ARPD in 2007.


Note 9 —	Common Stock and Stockholders’ Equity

Stock Plans— The Company’s employee and non-employee director stock plans are summarized as follows:

The current plan, the 2005 Long-Term Incentive Plan (“2005 Plan”), was approved by the shareholders at the Annual Meeting of Shareholders 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.

In 2008, the Company issued 900,474 restricted shares to selected key personnel. Incentive grants to senior management members included in this issuance were based upon the attainment of pre-established performance goals. The amortization expense in 2008 for awards related to 2008 and previously awarded

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

outstanding restricted shares was $7.0 million. In addition, during 2008 the Company obtained shareholder’s approval to increase the total number of common shares available for future awards under the 2005 Plan by 2,000,000 shares. This amendment to the 2005 Plan was approved by shareholders at the Company’s Annual Meeting on March 21, 2008.

In 2009, the Company issued 2,483,239 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. The amortization expense in 2009 for 2009 awards and previously awarded outstanding restricted shares was $4.3 million. The Company intends to seek shareholder approval at the 2010 annual meeting to amend the 2005 plan to the plan to increase the number of shares issued under the Plan.

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, 2008		—	$	—		290,300		$	2.877		—
Granted		—		—		—			—		—
Exercised		—		—		(85,000	)		2,349		—	$	183,664
Cancelled		—		—		(75,000	)		2.240		—

Outstanding at December 31, 2009		—	$	—		130,300		$	3.588		—

The following tables summarize the information regarding stock options outstanding and exercisable as of December 31, 2007:

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

1.990 - $4.200

130,300

1.21 years

3.588

177,469

Exercisable Options

Weighted

Average

Aggregate

Number of

Exercise

Intrinsic

Plan

Exercise Prices

Shares

Price

Value

1997 Stock Plan
Non-qualified

1.990 - $4.200

130,300

3.588

177,469

The Company had 1,574,176 and 1,457,862 shares held in treasury stock at December 31, 2009 and 2008, respectively.

Stock Reserved for Issuance— The following is a summary of common stock reserved for issuance:


	December 31,
	2009		2008

Stock plans		3,738,679		2,091,037
Stock bonus plan		24,666		355,359

Total shares reserved for issuance		3,763,345		2,446,396

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 10 —	Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS)


	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, 2007
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic EPS	$	102,846,000		109,542,364	$	0.94
Effect of dilutive securities:
Stock options and restricted stock				1,314,330	$	(0.01	)

Diluted EPS:	$	102,846,000		110,856,694	$	0.93

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.

For the year ended December 31, 2007, options to purchase 60,000 shares of common stock at prices ranging from $10.81 to $12.09 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.


Note 11 —	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 $2.3 million, $2.8 million and $2.5 million in 2009, 2008 and 2007, respectively. Employees become 100 percent vested in the employer match contributions within three months of service from date of hire.


Note 12 —	Reportable Segments

In 2008, as previously reported, the Company created a new reportable segment called project management and engineering services by combining our labor, operations and maintenance and engineering services contracts which had been previously reported in our U.S. drilling or international drilling segments. The new segment was created in anticipation of the significant expansion of these projects and services and senior management’s resultant separate performance assessment and resource allocation for this segment. The new segment operations, unlike our

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

U.S. and international drilling and rental tools operations, generally require little or no capital expenditures, and therefore have different performance assessment and resource needs. In the second quarter of 2008, the Company created a construction contract segment to reflect the Company’s Engineering, Procurement, Construction and Installation contract (“EPCI”). The construction contract segment income is accounted for on a percentage of completion basis using thecost-to-cost method. Revenues received and costs incurred related to the contract are recorded on a gross basis.


	Year Ended December 31,
Operations by Reportable Industry Segment	2009			2008			2007
	(Dollars in thousands)

Revenues:
International drilling(1)	$	293,337		$	325,096		$	213,566
U.S. drilling(1)		49,628			173,633			225,263
Rental tools(1)		115,057			171,554			138,031
Project management and engineering services(1)		109,445			110,147			77,713
Construction contract(1)		185,443			49,412			—

Total revenues		752,910			829,842			654,573

Operating income:
International drilling(2)		50,723			41,786			31,046
U.S. drilling(2)		(26,797	)		53,964			97,679
Rental tools(2)		27,841			74,689			59,264
Project management and engineering services(2)		23,646			18,470			12,732
Construction contract(2)		8,132			2,597			—

Total operating income		83,545			191,506			200,721
General and administrative expense		(45,483	)		(34,708	)		(24,708	)
Impairment of goodwill		—			(100,315	)		—
Provision for reduction in carrying value of certain assets		(4,646	)		—			(1,462	)
Gain on disposition of assets, net		5,906			2,697			16,432

Total operating income		39,322			59,180			190,983
Interest expense		(29,450	)		(29,266	)		(25,157	)
Changes in fair value of derivative positions		—			—			(671	)
Loss on extinguishment of debt		—			—			(2,396	)
Equity in loss of unconsolidated joint venture, net of taxes		—			(1,105	)		(27,101	)
Minority interest		—			—			(1,000	)
Other		(45	)		861			7,143

Income from continuing operations before income taxes	$	9,827		$	29,670		$	141,801

Identifiable assets:
International drilling	$	511,716		$	540,575
U.S. drilling		132,386			157,508
Rental tools		96,469			125,170

Total identifiable assets		740,571			823,253
Corporate assets		502,515			382,468

Total assets	$	1,243,086		$	1,205,721

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(1)		In 2009, BP accounted for approximately 23 percent of the Company’s total revenues, approximately $150.3 million of the Company’s construction contract segment revenues and approximately $2.6 million of the Company’s rental tools segment revenues. In 2009, ExxonMobil accounted for approximately 15 percent of the Company’s total revenues, approximately $75.7 million of the Company’s project management and engineering services segment revenues and approximately $20.7 million of the Company’s rental tools segment revenues. In 2008, ExxonMobil accounted for approximately 13 percent of the Company’s total revenues, approximately $62.2 million of the Company’s project management and engineering services segment revenues and approximately $22.3 million of the Company’s rental tools segment revenues. In 2007, ExxonMobil accounted for approximately 11 percent of the Company’s total revenues, approximately $63.0 million of the Company’s project management and engineering services segment revenues and approximately $11.4 million of the Company’s 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	2009		2008		2007
	(Dollars in thousands)

Capital expenditures:
International drilling	$	29,864	$	75,680	$	144,984
U.S. drilling		86,943		82,396		32,563
Rental tools		36,822		36,806		62,011
Corporate		9,155		2,188		2,540

Total capital expenditures	$	162,784	$	197,070	$	242,098

Depreciation and amortization:
International drilling	$	48,383	$	50,461	$	26,785
U.S. drilling		29,200		34,469		32,102
Rental tools		33,798		29,057		23,715
Corporate		2,594		2,969		3,201

Total depreciation and amortization	$	113,975	$	116,956	$	85,803

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Year Ended December 31,
Operations by Geographic Area	2009			2008			2007
	(Dollars in thousands)

Revenues:
Africa and Middle East	$	32,003		$	40,036		$	14,580
Asia Pacific		33,883			56,998			67,037
CIS		195,807			210,325			128,103
Latin America		117,651			122,521			75,683
United States		373,566			399,962			369,170

Total revenues		752,910			829,842			654,573

Operating income:
Africa and Middle East(1)		(2,795	)		(13,293	)		(14,466	)
Asia Pacific(1)		7,539			7,668			10,670
CIS(1)		44,647			37,068			18,914
Latin America(1)		20,964			27,072			26,825
United States(1)		13,190			132,991			158,778

Total operating income		83,545			191,506			200,721

General and administrative expense		(45,483	)		(34,708	)		(24,708	)
Impairment of goodwill		—			(100,315	)		—
Provision for reduction in carrying value of certain assets		(4,646	)		—			(1,462	)
Gain on disposition of assets, net		5,906			2,697			16,432

Total operating income		39,322			59,180			190,983
Interest expense		(29,450	)		(29,266	)		(25,157	)
Changes in fair value of derivative positions		—			—			(671	)
Loss on extinguishment of debt		—			—			(2,396	)
Equity in loss of unconsolidated joint venture, net of taxes		—			(1,105	)		(27,101	)
Minority interest		—			—			(1,000	)
Other		(45	)		861			7,143

Income from continuing operations before income taxes	$	9,827		$	29,670		$	141,801

Long-lived assets:(2)
Africa and Middle East	$	36,821		$	40,724
Asia Pacific		22,335			27,663
CIS		142,888			146,609
Latin America		61,322			63,560
United States		453,431			396,992

Total long-lived assets	$	716,797		$	675,548


(1)		Operating income is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

(2)		Long-lived assets primarily consist of property, plant and equipment, net and excludes assets held for sale, if any.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 13 —	Commitments and Contingencies

The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend through 2012 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses. Future minimum lease payments at December 31, 2009, under operating leases with non-cancelable terms are as follows:


	Year Ended
	December 31,
	(Dollars in Thousands)

2010	$	6,438
2011		2,932
2012		2,462
2013		1,946
2014		1,382
Thereafter		9,902

Total	$	25,062

Total rent expense for all operating leases amounted to $11.4 million for 2009, $13.7 million for 2008 and $10.1 million for 2007.

The Company is self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore liability), protection and indemnity (for offshore liability) and property damage. The Company’s exposure (that is, the retention or deductible) per occurrence is $250,000 for worker’s compensation, employer’s liability, general liability, protection and indemnity and maritime employers’ liability (Jones Act). In addition, the Company assumes a $750,000 annual aggregate deductible for protection and indemnity and maritime employers’ liability claims. The annual aggregate deductible is eroded by every dollar that exceeds the $250,000 per occurrence retention. The Company continues to assume a straight $250,000 retention for workers’ compensation, employers’ liability, and general liability losses. The self-insurance for automobile liability applies to historic claims only as the Company is currently on a first dollar policy, with those reserves being minimal. For all primary insurances mentioned above, the Company has excess coverage for those claims that exceed the retention and annual aggregate deductible. The Company maintains actuarially-determined accruals in its consolidated balance sheets to cover the self-insurance retentions.

The Company has self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political, war, and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for international operations. However, this coverage may not adequately protect the Company against liability from all potential consequences.

As of December 31, 2009, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $6.9 million and the related insurance recoveries/receivables were $1.9 million.

The Company has entered into employment agreements with terms of one to three years with certain members of management with automatic one or two year renewal periods at expiration dates. The agreements provide for, among other things, compensation, benefits and severance payments. They also provide for lump sum compensation and benefits in the event of termination within two years following a change in control of the Company.

The Company is a party to various lawsuits and claims arising out of the ordinary course of business. Management, after review and consultation with legal counsel, does not anticipate that any liability resulting from these matters would materially affect the results of operations, the financial position or the net cash flows of the Company. However, an adverse ruling not anticipated by the Company could have a material adverse effect on the results of operations or the financial position of the Company.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Kazakhstan Tax Claims

In connection with an October 2005 assessment of approximately KZT 7.4 billion or $62.5 million for corporate income taxes, the Kazakhstan Branch (“PKD Kazakhstan”) of Parker Drilling’s subsidiary, Parker Drilling Company International Limited (“PDCIL”), settled and paid the principal in December 2007. After an appeal of the interest portion of the notice of assessment, in February 2008, the Atyrau Economic Court issued a ruling that interest on the income tax assessed should accrue from the October 2005 assessment date. The interest portion of the assessment was paid by PKD Kazakhstan in March 2008, in final resolution of the income tax matter. Income tax for the year ended December 31, 2008 included a benefit of $13.4 million of FIN 48 interest and foreign currency exchange rate fluctuations related to this final resolution.

In connection with an October 2005 assessment of value added tax (“VAT Assessment”) on the importation of Barge Rig 257, administrative fines of approximately KZT 1.4 billion, or approximately $9.2 million, were assessed against PKD Kazakhstan, which assessment was appealed. In September 2009, a Kazakhstan court upheld the administrative fines related to the VAT Assessment. Amounts previously paid towards this fine totaled approximately KZT 18 million or $125 thousand. In February 2010, the remaining amount due of approximately KZT 1.3 billion, or approximately $9.1 million, was paid to the Atyrau Tax Committee in satisfaction of the fine. The Company has requested reimbursement of the full amount of the fine (totaling approximately $9.2 million) from our client, which is contractually obligated to reimburse PKD Kazakhstan for any administrative fines ultimately assessed.

Bangladesh Claim

In September 2005, a subsidiary of the Company was served with a lawsuit filed in the 152nd District Court of Harris County State of Texas on behalf of numerous citizens of Bangladesh claiming $250 million in damages due to various types of property damage and personal injuries (none involving loss of life) arising as a result of two blowouts that occurred in Bangladesh in January and June 2005, although only the June 2005 blowout involved the Company. The district court dismissed the case on the basis that Houston, Texas, is not the appropriate location for this suit to be filed. The plaintiffs appealed this dismissal. The Court of Appeals affirmed the dismissal which is now final because the plaintiffs failed to lodge an appeal with the Supreme Court within the required time period.

Asbestos-Related Claims

In August 2004, Parker Drilling was notified that certain of its subsidiaries have been named, along with other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred persons that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The complaints name as defendants numerous other companies that are not affiliated with Parker Drilling, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints.

The complaints allege that the Parker Drilling’s subsidiaries and other drilling contractors used asbestos-containing products in offshore drilling operations, land-based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability and claims under the Jones Act and that the plaintiffs are entitled to monetary damages. Based on the report of the special master, these complaints have been severed and venue of the claims transferred to the county in which the plaintiff resides or the county in which the cause of action allegedly accrued. Subsequent to the filing of amended complaints, Parker Drilling has joined with other co-defendants in filing motions to compel discovery to determine what plaintiffs have an employment relationship with which defendant, including whether or not any plaintiffs have an employment relationship with subsidiaries of Parker Drilling. Out of 668 amended single-plaintiff complaints filed to date, sixteen (16) plaintiffs have identified Parker Drilling or one of its affiliates as a defendant. Discovery is proceeding in groups of 60 and none of the plaintiff complaints naming Parker Drilling are included in the first 60 (Group I). The initial discovery of Group I resulted in certain dismissals with prejudice, two dismissals without prejudice and two withdraws from Group I, leaving only 40 plaintiffs remaining in Group I. Selection of Discovery

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Group II was completed on April 21, 2008. Out of the 60 plaintiffs selected, Parker Drilling was named in one suit in which the plaintiff claims that during 1973 he earned $587.40 while working for a former subsidiary of a company Parker Drilling acquired in 1996.

The subsidiaries named in these asbestos-related lawsuits intend to defend themselves vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome to have a material adverse effect on its financial condition, results of operations or cash flows. However, the Company is unable to predict the ultimate outcome of these lawsuits. No amounts were accrued at December 31, 2009.

Gulfco Site

In 2003, the Company received an information request under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) designating Parker Drilling Offshore Corporation, a subsidiary of Parker Drilling, as a potentially responsible party with respect to the Gulfco Marine Maintenance, Inc. Superfund Site in Freeport, Texas (EPA No. TX 055144539). The subsidiary responded to this request with documents. In January 2008 the subsidiary received an administrative order to participate in an investigation of the site and a study of the remediation needs and alternatives. The EPA alleges that the subsidiary is a successor to a party who owned the Gulfco site during the time when chemical releases took place there. Two other parties have been performing the investigation and study work since mid-2005 under an earlier version of the same order. The subsidiary believes that it has a sufficient cause to decline participation under the order and has notified the EPA of that decision. Non-compliance with an EPA order absent sufficient cause for doing so can result in substantial penalties under CERCLA. To date, the EPA and the other two parties have spent approximately $3.0 million studying and conducting initial remediation of the site. It is anticipated that at least an additional $1.3 million will be required to complete the remediation. Other costs (not yet quantified), such as interest and administrative overhead, could be added to any action against the Company. The Company currently anticipates that the total claim will not exceed $5 million and will be shared by all responsible parties. The Company has conducted an evaluation of the subsidiary’s relationship to the site and is engaged in discussions with the relevant parties in an effort to resolve the matter and to reduce potential risks and costs associated with possible litigation in the future.

Customs Agent and Foreign Corrupt Practices Act (“FCPA”) Investigation

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

We have taken certain steps to enhance our anti-bribery compliance efforts, including retaining a full-time Chief Compliance Officer who reports to the Chief Executive Officer and Audit Committee, and implementing efforts for the adoption of revised FCPA policies, procedures, and controls; increased training and testing requirements; contractual provisions for our service providers that interface with foreign government officials; due diligence and continuing oversight procedures for the review and selection of such service providers; and a compliance awareness improvement initiative that includes issuance of periodic anti-bribery compliance alerts.

Economic Sanctions Compliance

Kazakhstan Ministry of Finance Tax Audit

On August 14, 2009, the Kazakhstan Branch (“PKD Kazakhstan”) of Parker Drilling’s subsidiary, Parker Drilling Company International Limited (“PDCIL”), received an Act of Tax Audit from the Ministry of Finance of Kazakhstan (“MinFin”) for the period January 01, 2005 through December 31, 2007. PKD Kazakhstan was assessed additional taxes in the amount of KZT 1.45 billion (approximately USD $9.7 million) and associated interest in the amount of KZT 700 million (approximately USD $4.7 million). The amounts assessed relate to corporate income taxes and interest in connection with the disallowance of the head office’s management and administrative expenses, loan interest and state duties, as well as Value Added Taxes (“VAT”) and interest in connection with VAT offset on debts classified as doubtful by MinFin and for property taxes and interest in connection with Barge Rig 257 as a result of MinFin applying a lower rate of depreciation.

On September 25, 2009, PKD Kazakhstan appealed the Act of Tax Audit with MinFin on the basis the Branch exercised its rights provided by the Convention between the Governments of the Republic of Kazakhstan and the United States of America on the Avoidance of Double Taxation and the Prevention of the Fiscal Evasion with respect to Taxes on Income and Capital as well as improper application of Kazakhstan Tax Code provisions.

On January 13, 2010, PKD Kazakhstan received a response from MinFin to the appeal filed September 25, 2009. MinFin agreed with PKD Kazakhstan to remove the assessment related to property taxes and interest in connection with Barge Rig 257 which reduced the overall assessment by KZT 741 million (approximately USD

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$5 million). The residual assessment of KZT 959 million (approximately USD $6.5 million) of taxes and KZT 450 million (approximately USD $3 million) of associated interest remains outstanding.

PKD Kazakhstan intends to continue defending itself through court appeals. Based on the information available to the Company at this time, we do not expect the outcome to have a material adverse effect on our financial condition, results of operations or cash flows; however, we are unable to predict the ultimate outcome of this Act of Tax Audit. No amounts were accrued at December 31, 2009.


Note 14 —	Related Party Transactions

Consulting Agreement

The Company is party to a consulting agreement with Robert L. Parker Sr., the former Chairman of the Board of Directors of the Company and the father of the Company’s current Executive Chairman, Robert L. Parker Jr. Under the agreement, Mr. Parker Sr. was paid consulting fees of $180,667, $270,750 and $316,250 in each of the years ending December 31, 2009, 2008 and 2007, respectively. During 2007 and 2008, Mr. Parker Sr. and his spouse also received medical coverage under the Company’s medical plan.

During the term of the consulting agreement, Mr. Parker Sr. is required to maintain the confidentiality of any information he obtains while an employee or consultant and to disclose to the Company any ideas he conceives and assign to the Company any inventions he develops. For one year after the termination of the consulting agreement, Mr. Parker Sr. is prohibited from soliciting business from any of the Company’s customers or individuals with which the Company has done business, from becoming interested in any business that competes with the Company, and from recruiting any employees of the Company.

Under the consulting agreement, as amended, Mr. Parker Sr. continues to represent the Company on theU.S.-Kazakhstan Business Council, for which he receives a monthly payment of $14,583.34. Unless extended by the parties, the consulting agreement will terminate on April 30, 2010.

Other Related Party Agreements

During 2009 and 2008, one of the Company’s directors held the positions of President and of Executive Vice President and Chief Financial Officer, respectively, of Apache Corporation (“Apache”). During 2009 and 2008, affiliates of Apache paid affiliates of the Company a total of $6.8 million and $18.2 million, respectively, for performance of drilling services and provision of rental tools.


Note 15 —	Supplementary Information

At December 31, 2009, accrued liabilities included $2.8 million of deferred mobilization fees, $6.6 million of accrued interest expense, $5.7 million of workers’ compensation liabilities and $14.1 million of accrued payroll and payroll taxes. Other long-term obligations included $1.2 million of workers’ compensation liabilities as of December 31, 2009.

At December 31, 2008, accrued liabilities included $4.4 million of deferred mobilization fees, $7.3 million of accrued interest expense, $6.2 million of workers’ compensation liabilities and $25.9 million of accrued payroll and payroll taxes. Other long-term obligations included $1.9 million of workers’ compensation liabilities as of December 31, 2008.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 16 —	Selected Quarterly Financial Data


	Quarter
Year 2009	First		Second		Third		Fourth(2)			Total(2)
	(Unaudited)
	(Dollars in thousands except per share amounts)

Revenues	$	173,925	$	221,791	$	181,409	$	175,785		$	752,910
Operating gross margin	$	25,626	$	27,290	$	16,226	$	14,403		$	83,545
Operating income	$	12,644	$	16,868	$	4,882	$	4,928		$	39,322
Net income (loss)	$	2,106	$	4,391	$	7,094	$	(4,324	)	$	9,267
Basic earnings per share — net income (loss)(1)	$	0.02	$	0.04	$	0.06	$	(0.04	)	$	0.08
Diluted earnings per share — net income (loss)(1)	$	0.02	$	0.04	$	0.06	$	(0.04	)	$	0.08


	Quarter
Year 2008	First(2)		Second(2)		Third(2)		Fourth(2)			Total(2)
	(Unaudited)
	(Dollars in thousands except per share amounts)

Revenues	$	173,278	$	216,730	$	227,454	$	212,380		$	829,842
Operating gross margin	$	41,490	$	50,035	$	52,319	$	47,662		$	191,506
Operating income (loss)	$	35,401	$	42,190	$	43,847	$	(62,258	)	$	59,180
Net income (loss)	$	23,202	$	21,897	$	17,830	$	(40,201	)	$	22,728
Basic earnings per share — net income (loss)(1)	$	0.21	$	0.20	$	0.16	$	(0.36	)	$	0.20
Diluted earnings per share — net income (loss)(1)	$	0.21	$	0.19	$	0.16	$	(0.36	)	$	0.20


(1)		As a result of shares issued during the year, earnings per share for each of the year’s four quarters, which are based on weighted average shares outstanding during each quarter, may not equal the annual earnings per share, which is based on the weighted average shares outstanding during the year.

(2)		Total operating income and net income includes a gain of $15.1 million related to the sale of two barge rigs in the first quarter. Also included is a provision for reduction in carrying value of certain assets of $1.1 million recorded in the third quarter, and an equity loss in an unconsolidated joint venture of $1.1 million and $26.0 million in the third and fourth quarters, respectively. See Note 8 for further information on the joint venture. Net income in the first quarter included income tax expense of $7.0 million related to the sale of the two barge rigs and $1.9 million related to interest on tax uncertainties recorded. Net income in the second quarter included income tax expense of $4.0 million interest on tax uncertainties recorded. Net income in the fourth quarter included an income tax benefit of $25.6 million related to the settlement of tax matters related to accounting for uncertainties in income taxes. See Note 7 for further detail.


Note 17 —	Recent Accounting Pronouncements

Consolidation — 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 attributable to controlling interest and to noncontrolling interest be shown separately on the face of the statement of operations. The update also changes accounting for losses attributable to noncontrolling interests. Our adoption did not have a material effect on our consolidated balance sheet, statements of operations or cash flows.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


ITEM 9.	*CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE*

None


ITEM 9A.	*CONTROLS AND PROCEDURES*

Evaluation of Disclosure Controls and Procedures— The Company’s management, under the supervision and with the participation of the chief executive officer and chief financial officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined inRules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of December 31, 2009. In designing and evaluating the disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired control objectives, and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. Based on the evaluation, the chief executive officer and chief financial officer have concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports it files or submits with its periodic filings under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting —The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange ActRules 13a-15(f) and15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. The Company’s internal control over financial reporting includes those policies and procedures that:


	•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

	•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and

	•	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 risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management with the participation of the chief executive officer and chief financial officer assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included evaluation of the design and testing of the operational effectiveness of the Company’s internal control over financial reporting. Management reviewed the results of its assessment with the audit committee of the board of directors.

Based on that assessment and those criteria, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

KPMG LLP, the Company’s independent registered public accounting firm that audited the consolidated financial statements included in this Annual ReportForm 10-K, has issued a report with respect to the Company’s internal control over financial reporting as of December 31, 2009.

Changes in Internal Control over Financial Reporting —There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


ITEM 9B.	*OTHER INFORMATION*

None.

PART III


ITEM 10.	*DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE*

Information with respect to directors can be found under the captions “Item 1 — Election of Directors” and “Board of Directors” of the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010. Such information is incorporated herein by reference.

Information with respect to executive officers is shown in Item 1 of thisForm 10-K.

Information with respect to the Company’s audit committee and audit committee financial expert can be found under the caption “The Audit Committee” of the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010 and is incorporated herein by reference.

The information in the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010 set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

The Company has adopted the Parker Drilling Code of Corporate Conduct (“CCC”) which includes a code of ethics that is applicable to the chief executive officer, chief financial officer, controller and other senior financial personnel as required by the SEC. The CCC includes provisions that will ensure compliance with the code of ethics required by the SEC and with the minimum requirements under the corporate governance listing standards of the NYSE. The CCC is publicly available on the Company’s website athttp://www.parkerdrilling.com. If any waivers of the CCC occur that apply to a director, the chief executive officer, the chief financial officer, the controller or senior financial personnel or if the Company materially amends the CCC, the Company will disclose the nature of the waiver or amendment on the website and in a current report onForm 8-K within four business days.


ITEM 11.	*EXECUTIVE COMPENSATION*

The information under the captions “Executive Compensation,” “Fees and Benefit Plans for Non-Employee Directors,” “2010 Director Compensation Table,” “Option/SAR Grants in 2009 to Non-Employee Directors,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010 is incorporated herein by reference.


ITEM 12.	*SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS*

The information required by this item is hereby incorporated by reference to the information appearing under the captions “Security Ownership of Officers, Directors and Principal Shareholders” and “Equity Compensation Plan Information” in the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010.


ITEM 13.	*CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE*

The information required by this item is hereby incorporated by reference to such information appearing under the captions “Certain Relationships and Related Party Transactions” and “Director Independence Determination” in the Company’s 2010 Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2010.


ITEM 14.	*PRINCIPAL ACCOUNTING FEES AND SERVICES*

The information required by this item is hereby incorporated by reference to the information appearing under the captions “Audit and Non-Audit Fees” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm” in the Company’s 2010 Proxy Statement for the Annual Meeting of the Shareholders to be held on May 7, 2010.

PART IV


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES*

(a) The following documents are filed as part of this report:

(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:


	Page

Report of Independent Registered Public Accounting Firm		48
Consolidated Statement of Operations for the years ended December 31, 2009, 2008 and 2007		50
Consolidated Balance Sheet as of December 31, 2009 and 2008		51
Consolidated Statement of Cash Flows for the years ended December 31, 2009, 2008 and 2007		52
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2009, 2008 and 2007		53
Notes to the Consolidated Financial Statements		54
(2) Financial Statement Schedule:
Schedule II — Valuation and qualifying accounts		93

(3) Exhibits:


Exhibit
Number			Description

	3(a)	—	Restated Certificate of Incorporation of the Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report onForm 10-Q filed on November 9, 2007).
	3(b)	—	By-Laws of the Company, as amended on January 31, 2003 (incorporated by reference to the Company’s Annual Report onForm 10-K/A filed on September 26, 2003).
	4(a)	—	Indenture dated as of October 10, 2003 between the Company, as issuer, certain Subsidiary Guarantors (as defined therein) and JPMorgan Chase Bank, as Trustee, respecting the 9.625% Senior Notes due 2013 (incorporated by reference to the Company’s Registration Statement onForm S-4(No. 333-110374) filed on November 10, 2003).
	4(b)	—	Indenture, dated as of July 5, 2007, among Parker Drilling Company, the guarantors from time to time party thereto and The Bank of New York Trust Company, N.A., with respect to the 2.125% Convertible Senior Notes due 2013 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	4(c)	—	Form of 2.125% Convertible Senior Note due 2013 (included in Exhibit 4(b)).
	10(a)	—	Credit Agreement, dated as of May 15, 2008, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, the several banks and other financial institutions or entities from time to time parties thereto, ABN AMRO BANK N.V., as Documentation Agent, and Banc of America Securities LLC and Lehman Brothers Inc., as Joint Lead Arrangers and Book Managers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K filed on May 21, 2008).
	10(b)	—	Amended and Restated Parker Drilling Company Stock Bonus Plan effective as of January 1, 1999 (incorporated by reference to Exhibit 10(a) to the Company’s Quarterly Report onForm 10-Q filed on May 14, 1999).*


Exhibit
Number			Description

	10(c)	—	Parker Drilling Company Incentive Compensation Plan, dated December 17, 2008, and effective January 1, 2008 (incorporated by reference to Exhibit 10(b) to the Company’s Annual Report onForm 10-K filed on March 2, 2009).*
	10(d)	—	1994 Parker Drilling Company Limited Deferred Compensation Plan (incorporated herein by reference to Exhibit 10(h) to the Company’s Annual Report onForm 10-K filed on November 9, 1995).*
	10(e)	—	1994 Non-Employee Director Stock Option Plan (incorporated by reference to Exhibit 10(i) to the Company’s Annual Report onForm 10-K filed on November 9, 1995).*
	10(f)	—	1994 Executive Stock Option Plan (incorporated by reference to Exhibit 10(j) to the Company’s Annual Report onForm 10-K filed on November 9, 1995).*
	10(g)	—	Parker Drilling Company and Subsidiaries 1991 Stock Grant Plan (incorporated by reference to Exhibit 10(c) to the Company’s Annual Report onForm 10-K dated November 2, 1992).*
	10(h)(1)	—	Third Amended and Restated Parker Drilling 1997 Stock Plan effective July 24, 2002 (incorporated by reference to Exhibit 10(e) to the Company’s Annual Report onForm 10-K filed on March 20, 2003).*
	10(h)(2)	—	Form of Stock Option Award Agreement to the Third Amended and Restated Parker Drilling 1997 Stock Plan (incorporated by reference to Exhibit 10(m) to the Company’s Annual Report onForm 10-K filed on March 16, 2005).*
	10(h)(3)	—	Form of Stock Grant Award Agreement to the Third Amended and Restated Parker Drilling 1997 Stock Plan (incorporated by reference to Exhibit 10(n) to the Company’s Annual Report onForm 10-K filed on March 16, 2005).*
	10(i)(1)	—	2005 Long Term Incentive Plan (“2005 LTIP”) (incorporated by reference to the Annex E to the Company’s Definitive Proxy Statement filed on March 25, 2005).*
	10(i)(2)	—	First Amendment to the 2005 LTIP (incorporated by reference to Annex B to the Company’s Definitive Proxy Statement filed on March 21, 2008).*
	10(i)(3)	—	Second Amendment to the 2005 LTIP, dated December 13, 2008 (incorporated by reference to Exhibit 10(j) to the Company’s Annual Report onForm 10-K filed on March 2, 2009).*
	10(i)(4)	—	Form of Restricted Stock Award Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.2 to the Company’s Current Report onForm 8-K filed on May 3, 2005).*
	10(i)(5)	—	Form of Performance Based Restricted Stock Award Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.3 to the Company’s Current Report onForm 8-K filed on May 3, 2005).*
	10(j)	—	Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company (incorporated by reference to Exhibit 10(g) to the Company’s Annual Report onForm 10-K filed on March 20, 2003).*
	10(k)	—	Form of Employment Agreement entered into between Parker Drilling Company and certain executive and other officers of Parker Drilling Company, (incorporated by reference to Exhibit 10(h) to the Company’s Annual Report onForm 10-K filed on March 20, 2003).*
	10(l)	—	Form of Lease Agreement between Parker Drilling Management Services, Inc. entered into by the Robert L. Parker Sr. Family Limited Partnership and Robert L. Parker Jr. dated January 1, 2004 (incorporated by reference to Exhibit 10(a) to the Company’s Quarterly Report onForm 10-Q filed on August 9, 2004).*
	10(m)	—	Form of Personnel Services Contract between Parker Drilling Management Services, Inc. and the Robert L. Parker Sr. Family Limited Partnership and Robert L. Parker Jr. dated January 1, 2004 (incorporated by reference to Exhibit 10(b) to the Company’s Quarterly Report onForm 10-Q filed on August 9, 2004).*
	10(n)(1)	—	Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated April 12, 2006 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K filed on April 12, 2006).*


Exhibit
Number				Description

	10(n)(2)		—	Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., effective as of May 1, 2008 (incorporated by reference to Exhibit 10(t) to the Company’s Annual Report onForm 10-K filed on March 2, 2009).*
	10(n)(3)		—	Second Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., dated May 1, 2009.*
	10(o)		—	Termination of Split Dollar Life Insurance Agreement between Parker Drilling Company, Robert L. Parker Sr., and Robert L. Parker Sr. and Catherine Mae Parker Family Trust dated April 12, 2006 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report onForm 8-K filed on April 12, 2006).*
	10(p)		—	Confirmation of Convertible Bond Hedge Transaction, dated as of June 28, 2007, by and between Parker Drilling Company and Bank of America, N.A (incorporated by reference to Exhibit 10.1 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(q)		—	Confirmation of Convertible Bond Hedge Transaction, dated as of June 28, 2007, by and between Parker Drilling Company and Deutsche Bank AG, London Branch (incorporated by reference to Exhibit 10.2 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(r)		—	Confirmation of Convertible Bond Hedge Transaction, dated as of June 28, 2007, by and between Parker Drilling Company and Lehman Brothers OTC Derivatives Inc. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(s)		—	Confirmation of Issuer Warrant Transaction dated as of June 28, 2007, by and between Parker Drilling Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.4 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(t)		—	Confirmation of Issuer Warrant Transaction, dated as of June 28, 2007, by and between Parker Drilling Company and Deutsche Bank AG, London Branch (incorporated by reference to Exhibit 10.5 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(u)		—	Confirmation of Issuer Warrant Transaction dated as of June 28, 2007, by and between Parker Drilling Company and Lehman Brothers OTC Derivatives Inc. (incorporated by reference to Exhibit 10.6 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(v)		—	Amendment to Confirmation of Issuer Warrant Transaction dated as of June 29, 2007, by and between Parker Drilling Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.7 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(w)		—	Amendment to Confirmation of Issuer Warrant Transaction, dated as of June 29, 2007, by and between Parker Drilling Company and Deutsche Bank AG, London Branch (incorporated by reference to Exhibit 10.8 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	10(x)		—	Amendment to Confirmation of Issuer Warrant Transaction, dated as of June 29, 2007, by and between Parker Drilling Company and Lehman Brothers OTC Derivatives Inc. (incorporated by reference to Exhibit 10.9 to the Company’s Current Report onForm 8-K filed on July 5, 2007).
	21		—	Subsidiaries of the Registrant.
	23	.1	—	Consent of KPMG LLP.
	31	.1	—	David C. Mannon, President and Chief Executive Officer,Rule 13a-14(a)/15d-14(a) Certification.
	31	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer,Rule 13a-14(a)/15d-14(a) Certification.
	32	.1	—	David C. Mannon, President and Chief Executive Officer, Section 1350 Certification.
	32	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.


*		— Management contract, compensatory plan or agreement.

PARKER DRILLING COMPANY AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


	Balance		Charged
	at		to Cost			Charged				Balance
	Beginning		and			to Other				at End of
Classifications	of Year		Expenses			Accounts		Deductions		Year
	(Dollars in thousands)

Year ended December 31, 2009
Allowance for doubtful accounts and notes	$	3,169	$	2,246		$	—	$	1,320	$	4,095
Deferred tax valuation allowance	$	4,556	$	638		$	—	$	—	$	5,194
Year ended December 31, 2008
Allowance for doubtful accounts and notes	$	3,152	$	76		$	—	$	59	$	3,169
Reduction in carrying value of rig materials and supplies	$	2,607	$	(903	)	$	—	$	1,704	$	—
Deferred tax valuation allowance	$	6,391	$	—		$	—	$	1,835	$	4,556
Year ended December 31, 2007
Allowance for doubtful accounts and notes	$	1,481	$	1,975		$	—	$	304	$	3,152
Reduction in carrying value of rig materials and supplies	$	4,337	$	(590	)			$	1,140	$	2,607
Deferred tax valuation allowance	$	—	$	—		$	6,391	$	—	$	6,391

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PARKER DRILLING COMPANY


	By:	/s/ W. Kirk Brassfield

W. Kirk Brassfield

Senior Vice President and Chief Financial Officer

Date: March 3, 2010

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


Signature		Title	Date


By:	/s/ Robert L. Parker Jr. Robert L. Parker Jr.	Executive Chairman and Director	March 3, 2010

By:	/s/ David C. Mannon David C. Mannon	President and Chief Executive Officer (Principal Executive Officer)	March 3, 2010

By:	/s/ W. Kirk Brassfield W. Kirk Brassfield	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	March 3, 2010

By:	/s/ Philip A. Schlom Philip A. Schlom	Controller (Principal Accounting Officer)	March 3, 2010

By:	/s/ George J. Donnelly George J. Donnelly	Director	March 3, 2010

By:	/s/ John W. Gibson, Jr. John W. Gibson, Jr.	Director	March 3, 2010

By:	/s/ Robert W. Goldman Robert W. Goldman	Director	March 3, 2010

By:	/s/ Gary R. King Gary R. King	Director	March 3, 2010

By:	/s/ Robert E. McKee III Robert E. McKee III	Director	March 3, 2010

By:	/s/ Roger B. Plank Roger B. Plank	Director	March 3, 2010

By:	/s/ R. Rudolph Reinfrank R. Rudolph Reinfrank	Director	March 3, 2010

INDEX TO EXHIBITS


Exhibit
Number				Description

	10(n)(3)		—	Second Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., dated May 1, 2009.
	21		—	Subsidiaries of the Registrant.
	23	.1	—	Consent of KPMG LLP — Independent Registered Public Accounting Firm.
	31	.1	—	David C. Mannon, President and Chief Executive Officer,Rule 13a-14(a)/15d-14(a) Certification.
	31	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer,Rule 13a-14(a)/15d-14(a) Certification.
	32	.1	—	David C. Mannon, President and Chief Executive Officer, Section 1350 Certification.
	32	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

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Parker Drilling (PKDC) 10-K2009 FY Annual report

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