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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
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		(I.R.S. Employer
incorporation or organization)		Identification No.)

1401 Enclave Parkway, Suite 600, Houston, Texas 77077

(Address of principal executive offices) (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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	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 in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of our common stock held by non-affiliates on June 30, 2008 was $941.9 million. At January 31, 2009, there were 113,455,821 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 April 21, 2009 are incorporated by reference in Part III.

PART I


ITEM 1.	*BUSINESS*

General

Parker Drilling Company was incorporated in the state of Oklahoma in 1954. 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. 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. We make available free of charge on our website at www.parkerdrilling.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (“SEC”). Additionally, these reports are available on an Internet website maintained by the SEC at http://www.sec.gov. We voluntarily provide paper or electronic copies of our reports free of charge upon request.

The address of the corporate headquarters is 1401 Enclave Parkway, Suite 600, Houston, Texas 77077.

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. Our quality, health, safety and environmental policies and procedures are best in class.

Our 2008 revenues are derived from five segments:


	•	U.S. Drilling;


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

	•	Project Management and Engineering Services;

	•	Rental Tools; and

	•	Construction Contract services.

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, 2008, our fleet of rigs consisted of:


	•	nine land rigs in the Commonwealth of Independent States (currently includes operations in Kazakhstan and Turkmenistan and referred to as the “CIS”);

	•	eight land rigs in the Asia Pacific region;

	•	nine land rigs in Latin America (Mexico and Colombia) region;

	•	one barge drilling rig in the inland waters of Mexico;

	•	two land rigs in the Africa/Middle East region (Algeria);

	•	the world’s largest arctic-class barge rig in the Caspian Sea;

	•	15 barge drilling and workover rigs in the transition zones of the U.S. Gulf of Mexico; and

	•	One land rig in the Company’s construction yard in New Iberia.


ITEM 1.	*BUSINESS (continued)*

Our Project Management and Engineering Services Business

We also provide non-capital intensive services such as Front End Engineering and Design (“FEED”) and Engineering, Procurement, Construction and Installation (EPCI) services and project management services (labor, maintenance, logistics, etc.) for operators who own their own drilling rigs and who choose to rely upon our technical expertise. We are currently involved in one FEED study project and have project management activities in Alaska, Kuwait and Sakhalin Island, Russia.

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 one-fourth of Quail Tools’ equipment is utilized in offshore and coastal water operations of the Gulf of Mexico. Quail Tools’ base of operations is in New Iberia, Louisiana. Other facilities are located in Texas, Wyoming and North Dakota. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the Gulf of Mexico and other major U.S. energy producing markets. Quail Tools also provides rental tools to customers operating internationally in Trinidad and Tobago, Mexico, Russia, Singapore, Nigeria, Brazil and Chad.

Construction Contracts Business

In April 2008, the Company was awarded the EPCI phase of the BP Liberty extended reach drilling rig project. The rig is scheduled for delivery in early 2010.

Our Market Areas

U.S. Gulf of Mexico. The drilling industry in the U.S. Gulf of Mexico is characterized by highly cyclical activity where utilization and dayrates are typically driven by current natural gas prices. Within this area, we operate barge rigs primarily in shallow coastal water off the coasts of Louisiana and Texas. Approximately two-thirds of our barge rigs, including our three ultra-deep drilling barge rigs, are typically contracted by oil and gas companies to drill gas prospects and one-third to drill oil prospects. These contracts are typically medium term, well-to-well, with a duration of 60 to 150 days, with a few barge rigs contracted for terms longer than six months.

International Markets. The majority of the international drilling markets in which we operate have one or more of the following characteristics: (i) customers who typically are major, large independent or national energy companies, or integrated service providers; (ii) drilling programs in remote locations with little infrastructure and/or harsh environments requiring specialized drilling equipment with a large inventory of spare parts and other ancillary equipment; and (iii) difficult (i.e., high pressure, deep, hazardous or geologically challenging) wells requiring specialized equipment and considerable experience to drill. Typically, our international contracts have multi-year terms.

Our Strategy

Our strategy is to maintain and leverage our position as a leading provider of drilling, project management and engineering and rental tools services to the energy industry. Our goal is to position our Company as the contractor of choice by providing dependable and efficient drilling performance, innovative drilling solutions and high-quality rental tools services. We manage our operations in accordance with a long-term strategic plan. Key elements of our strategy include:

Pursuing Strategic Growth Opportunities. Our newest 3,000 Horsepower (“HP”) barge rig designed specifically for deep well programs in the U.S. Gulf of Mexico (“GOM”) has been a preferred barge rig to operators in the GOM. Two of four new 2,000 HP international land rigs, which include Alternating Current (“AC”) variable frequency drives, were delivered early in 2007 for drilling operations in Algeria and later in


ITEM 1.	*BUSINESS (continued)*

Our Strategy (continued)

2007 the third and fourth rigs were delivered to Mexico. In addition, during 2008 we completed construction of two of our new design, high-efficiency class rigs. The new high-efficiency rig is a 2,000 HP land rig that incorporates advanced features such as “plug and play” adaptability and quick mobilization ability, in addition to AC variable speed drives, to meet the increasing requirements of operators. The first rig is being utilized to perform a contract in Kazakhstan and began operations in August 2008.

As a result of increased activity at our rental tools satellite operation in Williston, North Dakota, we expanded this location to a full-scale facility, which opened in January 2008.

Sustaining the Preference for Our Barge and Land Rigs. We sustain the preference for our barge and land rigs by building and upgrading our fleet of premium rigs that we feel will be preferred regardless of the position in the energy business cycle and through strategic placement in areas which evidence long term development opportunities.

Focusing on an Efficiency-Based Operating Philosophy for Operating Costs, Preventive Maintenance and Capital Expenditures. We continue to be vigilant in monitoring and controlling costs. Our operating philosophy emphasizes continuous improvement of processes, equipment standardization and global quality, safety and supply chain management. Capital expenditures are aligned with core objectives and our preventive maintenance programs facilitate dependable operating efficiency and minimize down time, helping establish us as a “contractor of choice.’’

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 in Algeria, Colombia, Indonesia, Kazakhstan, Kuwait, Mexico, New Zealand, Papua New Guinea, Russia, Turkmenistan 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 drilling contractors in the world. Our international revenues constituted approximately 52 percent of our total revenues in the twelve months ended December 31, 2008.

Outstanding Safety, Preventive Maintenance, Inventory Control and Training Programs. We have an outstanding safety record. In 2008, 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 for the last ten years. In recognition of our achievements we were named one of America’s Safest Companies by Occupational Hazards magazine in 2007. This, along with integrated quality and 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 center provides safety and technical training curriculums in four different languages and provides regulatory compliance training throughout the world.

Strong and Experienced Senior Management Team. Our management team has extensive experience in the contract drilling industry. Our chairman and chief executive officer, Robert L. Parker Jr. joined Parker Drilling in 1973 and has served as our president from 1977 through June 2007, chief executive officer since 1991 and chairman of the board since April 2006. Under the leadership of Mr. Parker Jr., we have continued our reputation as a leading worldwide provider of contract drilling services. David C. Mannon 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 over 25 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


ITEM 1.	*BUSINESS (continued)*

Our Competitive Strengths (continued)

president, controller and principal accounting officer. He brings 29 years of experience to the management team, including 16 years in the oil and gas industry. Denis Graham, vice president of engineering, brings over 27 years of experience in drilling industry engineering design, maintenance and regulatory compliance and has established an excellent reputation for Parker through management of large engineering projects for major oil companies.

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 Exxon Neftegas Limited (“ENL”) and currently manage drilling operations under a five-year Operations and Maintenance (“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 supervised construction of a second rig to drill from the Orlan platform and began a five-year O&M contract for ENL offshore Sakhalin, Russia in September 2005.

During 2007 we began working on a technical service FEED study for BP America to provide a land-based drilling rig conceptual design for its Liberty Project in the Alaskan Beaufort Sea. Parker commenced construction of this rig for BP pursuant to an EPCI contract in April 2008 and anticipates delivery of the rig to BP in early 2010. Parker expects to be awarded the Operations and Maintenance (“O&M”) contract for the rig from BP, which will include the drilling of extended-reach wells, some of which are expected to extend to nominal measured depths in excess of 40,000 feet.

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

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 the U.S. Gulf of Mexico barge drilling market we are awarded most contracts through a competitive bidding process. We have achieved some success in differentiating ourselves from competitors through our upgraded fleet and preventive maintenance programs which lead to a more efficient and safer operation.

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, but the operators often consider factors other than the lowest price, including technical expertise and quality of equipment. National drilling contractors have increased competition in international markets in recent years. Although national drilling contractors typically have lower labor and mobilization costs, we are generally able to distinguish ourselves from these national companies based on our technical expertise, quality of our equipment, preventive 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.

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

Customers

Our drilling and rental tools customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2008 our two largest customers, ExxonMobil (including subsidiaries and joint ventures), and Schlumberger accounted for approximately 13 percent and 9 percent of


ITEM 1.	*BUSINESS (continued)*

Customers (continued)

our total revenues, respectively. Our ten most significant customers collectively accounted for approximately 56 percent of our total revenues in 2008.

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. At the core of our operating philosophy are the four pillars of a preferred drilling contractor: Safety, Training, Performance and Technology.

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, or no payment if the conditions continue beyond a certain time. 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 may be terminated by the customer prior to the end of the term without penalty under certain circumstances, such as the loss or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. The majority of our contracts require the operator to pay an early termination fee if the operator terminates a contract before the end of the term without cause, but in the remainder of the contracts the operator 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 reimburse Parker for lost or damaged equipment.

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.


ITEM 1.	*BUSINESS (continued)*

Employees

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


	December 31,
	2008		2007

International operations		1,801		2,055
U.S. operations		445		558
Rental tools		280		255
Corporate and other		240		219

Total employees		2,766		3,087

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 are in substantial compliance 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


ITEM 1.	*BUSINESS (continued)*

Environmental Considerations (continued)

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. barge 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. Several years ago we received an information request under CERCLA identifying 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. TXD055144539). We responded with information and documents. In January, 2008 we received an administrative order to participate in an


ITEM 1.	*BUSINESS (continued)*

Environmental Considerations (continued)

investigation of the site and a study of the remediation needs and alternatives. EPA alleges that Parker is successor to a party who owned the Gulfco site during the time when chemical releases took place there. Two other parties have been performing that work since mid-2005 under an earlier version of the same order. We believe that we have sufficient cause to decline participation under the order and have 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. We are continuing to evaluate our relationship to the site and intend to confer with the EPA in an effort to resolve the matter. We have not yet estimated the amount or impact on our operations, financial position or cash flows of any costs related to the site. EPA and the other two parties have spent over $2.5 million studying and conducting some remedial work at the site and it is anticipated that an additional $1.3 million will be required to complete the remediation based on current information.

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” 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 United States Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) and possibly from stationary sources as well under certain federal Clean Air Act programs, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and the demand for hydrocarbon products generally. The impact of such future programs cannot be predicted, but we do not expect material adverse affects to our operations at this time.

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, U.S. drilling, international drilling, project management and engineering, rental tools and construction contract. Information about our business segments and operations by geographic areas for the years ended December 31, 2008, 2007 and 2006 is set forth in Note 12 in the notes to the consolidated financial statements included in Item 8 of this report.


ITEM 1.	*BUSINESS (continued)*

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:

(1) Robert L. Parker Jr., 60, chairman and chief executive officer, joined Parker Drilling in 1973 as a contract representative and was named manager of U.S. operations later in 1973. He was elected a vice president in 1973, executive vice president in 1976 and was named president and chief operating officer in October 1977. In December 1991, he was named chief executive officer, and was elected chairman in April 2006. He has been a director since 1973.

(2) David C. Mannon, 51, president and chief operating officer, joined Parker Drilling in December 2004 as senior vice president and chief operating officer. He was appointed president in July 2007. From April 2003 through November 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. Mr. Mannon is currently a member of the International Association of Drilling Contractors (IADC), Society of Petroleum Engineers (SPE) and the American Association of Drilling Engineers (AADE), and also serves on the Upstream Committee of the American Petroleum Institute (API).

(3) W. Kirk Brassfield, 53, senior vice president and chief financial officer, joined Parker Drilling in March 1998 as controller and principal accounting officer. From 1991 through March 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.

(4) Denis J. Graham, 59, vice president of engineering, joined Parker Drilling in 2000 as vice president of engineering. Mr. Graham has nearly 30 years of industry experience. Prior to joining Parker Drilling, he held the position of senior vice president of technical services for Diamond Offshore Drilling Company. Mr. Graham is a Registered Professional Engineer in the State of Texas and holds a master of engineering/civil structural degree from the University of Houston and a bachelor of science/ocean engineering degree from Texas A & M University.

(5) Ronald C. Potter, 55, vice president and general counsel, re-joined Parker Drilling in June 2003 as vice president and general counsel. From 2001 through May 2003, Mr. Potter was Parker Drilling’s outside legal counsel as a shareholder of Conner & Winters, P.C. in Tulsa, Oklahoma. From 1980 to 2001, he served Parker Drilling in various positions, most recently as chief legal counsel and corporate secretary.

(6) Lynn G. Cullom, 54, principal accounting officer and corporate controller, joined Parker Drilling in August 2004 as director of corporate planning. She was named principal accounting officer in October 2005 and controller in March 2005. From March 2001 through August 2004, Ms. Cullom served in various accounting and reporting director positions at El Paso Corporation, most recently as Director of Power Asset Accounting, from January 2003 through February 2004, and as Accounting Director for Power, Petroleum, Field Services and Other Assets, from February 2004 through July 2004. Ms. Cullom served in various positions for Coastal Corporation from September 1979 through February 2001, including vice president of financial reporting and planning for Coastal Mart, a subsidiary.

(7) Michael D. Drennon, 53, vice president- operations, joined Parker Drilling in December 2005 as vice-president-operations. From July 2000 through November 2005, Mr. Drennon served as program director for development of company operated discoveries in Angola for BP p.l.c. Mr. Drennon served in various engineering, operations and management assignments from 1977 through 2000 with Amoco and BP p.l.c.


ITEM 1.	*BUSINESS (continued)*

EXECUTIVE OFFICERS (continued)

Other Parker Drilling Company Officer

(8) David W. Tucker, 53, 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.

ITEM 1A. RISK FACTORS

The contract drilling, project management/engineering, construction 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 this Form 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

Due to the on-going volatility in oil and natural gas prices, the ongoing credit crisis, and the deteriorating global economic environment, certain customers have curtailed or delayed drilling programs. We are unable to anticipate whether or not our customers will further curtail or delay drilling programs. There is a risk that our vendors will not fulfill their commitments. The global economic conditions 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 and rental tool business.

Our business depends to a significant extent on the level of international onshore drilling activity and offshore drilling activity for natural gas in the Gulf of Mexico. Oil and gas prices have declined significantly during recent months in a deteriorating global economic environment. If oil and natural gas prices continue to decline this could cause oil and gas companies to further decrease spending on drilling activity, which in turn could result in a reduction in dayrates and utilization.

In addition, operators who depend on financing for their drilling projects may be forced to curtail or delay these projects and may also experience an inability to pay suppliers and service providers, including the Company. The deteriorating global economic environment also could impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. We are unable to predict the nature and extent that this volatility in oil and natural gas prices and global economic crisis may have on our business and financial results.

Rig upgrade, refurbishment and construction projects are subject to risks, 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 preventive maintenance system or contractual requirements or when repairs are required or to comply with environmental regulations. We may also make significant expenditures when we move rigs from one location to another. 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;

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)


	•	delays relating to inaccessibility of credit markets;

	•	long lead times for manufactured rig components;

	•	unanticipated repairs to correct defects in construction not covered by warranty;

	•	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.

Significant cost overruns or delays could adversely affect our financial condition and results of operations. 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 technical services and support for our drilling operations. Although we use our training center to train personnel and promote from within, it has become more difficult to retain existing personnel.

Our ability to service our debt obligations is primarily dependent upon our future financial performance.

As of December 31, 2008, we had:


	•	$455.1 million of long-term debt;

	•	$6.0 million of current portion of long-term debt;

	•	$8.6 million of operating lease commitments; and

	•	$12.8 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.

Cash flows from operating activities have been strong in recent years. However, 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:


	•	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

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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 (we anticipate that our capital expenditures in 2009 will be approximately $180 — $200 million, including approximately $30 — $35 million for maintenance projects). 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.

Due to the current credit crisis and our leveraged capital structure, 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.

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 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

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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. Generally, changes in the price of oil have a greater impact on our international operations while changes in the price of natural gas have a greater impact on our operations in the Gulf of Mexico.

Demand for our drilling and related services also depends upon other factors, many of which are beyond our control, including:


	•	the cost of producing and delivering oil and natural gas;

	•	advances in exploration, development and production technology;

	•	laws and government regulations, both in the United States and other countries;

	•	the imposition or lifting of economic sanctions against foreign countries;

	•	recent rig construction projects which may create overcapacity;

	•	local and worldwide military, political and economic events, including events in the oil producing countries in the Middle East, Southeast Asia and Latin America;

	•	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 demand;

	•	the rate of discovery of new oil and natural gas reserves;

	•	the development and use of alternative energy sources;

	•	the policies of various governments regarding exploration and development of their oil and natural gas reserves.

Most of our contracts are subject to cancellation by our customers without penalty with little or no notice.

Most of our contracts are subject to cancellation by our customers without penalty with relatively little or no notice. Customers are more likely to seek renegotiation of contract terms or to exercise their termination rights when drilling market conditions are depressed.

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 adversely affect our financial performance.

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 2008, our two largest customers, ExxonMobil (including subsidiaries and joint ventures) and Schlumberger accounted for approximately 13 percent and 9 percent of our total revenues, respectively. Our ten most significant customers collectively accounted for approximately 56 percent of our total revenues in 2008. 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

Contract drilling and the rental tools business are highly competitive.

The contract drilling and rental tools markets are highly competitive and no single competitor is dominant. Although the international drilling market has not experienced any material decrease in utilization as a result of the credit crisis and worldwide economic downturn, demand in the Gulf of Mexico barge market has decreased significantly during the past few months. During periods of decreased demand we historically experience significant reductions in dayrates and utilization. We anticipate that current demand for our rental tools to maintain at or near current levels for the foreseeable future. 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. We have previously reported that historically 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, as we expect this to occur based on current market conditions. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. We believe that competition for drilling contracts will continue to be intense for the foreseeable future. If we cannot keep our rigs utilized, our financial performance will be adversely impacted. The rental tools market is also characterized by vigorous competition among several competitors. Many of our competitors in both the contract drilling and rental tools business possess greater financial resources than we do.

Our international operations could be adversely affected by terrorism, war, civil disturbances, political instability and similar events.

We have operations in 10 foreign countries. Our international operations are subject to interruption, suspension and possible expropriation due to terrorism, war, civil disturbances, political 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 such risks, 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 2008, we derived approximately 52 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;

	•	hiring and retaining skilled and experienced workers, many of whom are represented by foreign labor unions;

	•	unfavorable changes in foreign monetary and tax policies and unfavorable and inconsistent interpretation and application of foreign tax laws;

	•	foreign currency fluctuations and restrictions on currency repatriation; 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. Additionally, our ability to compete in international contract drilling markets may be adversely affected by

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

foreign governmental regulations or other policies that favor the awarding of contracts to contractors in which nationals of those foreign countries have substantial ownership interests. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions or fees from time to time on the transfer of funds to us. While we have been successful in most cases in contractually limiting these risks by transferring the risk of loss to the operators, we cannot completely eliminate such risks.

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 have historically been successful in limiting the risks of currency fluctuation and restrictions on currency repatriation by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currencies. However, some countries in which we may operate could require that all or a portion of our revenues be paid in local currencies that are not freely convertible. In addition, some parties with which we do business may require that all or a portion of our revenues be paid in local currencies. To the extent possible, we limit our exposure to potentially devaluating currencies by matching the acceptance of local currencies to our local expense requirements in those currencies. Although we have done this in the past, we may not be able to obtain such contractual terms in the future, thereby exposing us to foreign currency fluctuations that 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 flights and/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.

Compliance with foreign tax and other laws may adversely affect our operations.

Tax and other laws and regulations are not always interpreted consistently among local, regional and national authorities. See Note 13 in the notes to the consolidated financial statements for an example of pending tax disputes. The ultimate outcome of these disputes is not certain, and it is possible that the outcome could have an adverse effect on our financial performance. It is also possible that in the future we will be subject to similar disputes concerning taxation and other matters in countries in which we do business, and these disputes could have a material 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, 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. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we generally obtain indemnification from our customers by contract for some of these risks. However, the laws of certain countries place significant limitations on the enforceability of indemnification provisions that allow a contractor to be indemnified for damages resulting from the drilling contractor’s fault. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. However, we have self-insured retention or deductibles for certain losses relating to workers’ compensation, employers’ liability,

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

general liability (for onshore liability), protection and indemnity (for offshore liability), and property damage. In addition, insurance for some risks, such as reservoir damage, is not available. For further information, see Note 13 in the notes to the consolidated financial statements. These insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the hazards and risks described above. 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. 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.

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 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 this Form 10-K for a discussion of the material legal proceedings affecting us.

We are subject to the Foreign Corrupt Practices Act (“FCPA”) and other laws concerning our international operations, and currently are conducting an investigation into possible violations. 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.

The Company operates in a number of jurisdictions that pose an elevated risk of potential violations under the FCPA and other laws concerning our international operations. As previously disclosed, the Company received requests from the 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 freight forwarding and customs agent. In response to these requests, the Company is conducting an internal investigation. 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 SEC are investigating the Company’s use of customs and freight forwarding services 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. At this point, we are unable to predict the duration, scope or result of the DOJ and SEC investigations or whether either agency will commence any legal action. If we are not in compliance with the

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

FCPA and other laws governing the conduct of our business in international locations (including other United States laws and regulations as well as local laws), we may be subject to criminal and civil penalties and other remedial measures, which could have an 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 are conducting an internal review concerning our compliance with these legal requirements. 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.

Our international operations 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 that may have violated applicable U.S. laws and regulations. In addition, we have engaged in drilling wells in the Korpedje Field in Turkmenistan, from where natural gas may be exported by pipeline to Iran. We are currently reviewing 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. Although we are unable to predict the scope or result of this internal review or its ultimate outcome, we have initiated voluntary disclosure of these potential compliance issues to the appropriate U.S. government agency. Any violations of these laws and regulations, including fines, penalties or restrictions on routes of shipping and drilling activities, could adversely affect our reputation and the market for our shares, and may require certain of our investors to disclose their investment in our Company under certain state laws. If we are 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

Market price of our common stock currently changing significantly.

The market price of our common stock currently changing significantly in response to various factors and events, most of which are beyond our control, including the following:


	•	the other risk factors described in this Form 10-K, including changes in oil and natural gas prices;

	•	a shortfall in rig utilization, operating revenue or net income from that expected by securities analysts and investors;

	•	changes in securities analysts’ estimates of the financial performance of us or our competitors or the financial performance of companies in the oilfield service industry generally;

	•	changes in actual or market expectations with respect to the amounts of exploration and development spending by oil and gas companies;

	•	general conditions in the economy and in the energy-related industries;

	•	general conditions in the securities markets;

	•	political instability, terrorism or war; and

	•	the outcome of pending and future legal proceedings, tax assessments and other claims.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Common Stock (continued)

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

Payment of principal and interest on our 9.625% Senior Notes will be effectively subordinated to our senior secured debt to the extent of the value of the assets securing that debt.

Our 9.625% Senior Notes and the guarantees related to those notes are senior unsecured obligations of Parker Drilling and certain of our subsidiaries that rank senior in right of payment to all current and future subordinated debt. Holders of our secured obligations, including obligations under our senior secured credit facility, will have claims that are prior to claims of the holders of our notes with respect to the assets securing those obligations. In the event of a liquidation, dissolution, reorganization, bankruptcy or any similar proceeding, our assets and those of our subsidiaries would be available to pay obligations on the notes and the guarantees only after holders of our senior secured debt have been paid the value of the assets securing such debt. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the notes.

We have granted the lenders under our senior secured credit facility a security interest in (i) all accounts receivable and certain deposit accounts, of (a) Parker Drilling Company and (b) substantially all of our domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries (“subsidiary guarantors”), (ii) a pledge of stock of the subsidiary guarantors, certain immaterial subsidiaries and first tier foreign subsidiaries; (iii) a naval mortgage on certain eligible barge drilling rigs owned by a subsidiary guarantor and (iv) substantially all of the personal property assets of our rental tools business. In the event of a default on secured indebtedness, the parties granted security interests will have a prior secured claim on such assets. If the parties should attempt to foreclose on their collateral, our financial condition and the value of the notes would be adversely affected.

We are a holding company and conduct substantially all of our operations through our subsidiaries, which may affect our ability to make payments on our notes.

We conduct substantially all of our operations through our subsidiaries. As a result, our cash flows and our ability to service our debt, including our notes, is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory restrictions, including local law, monetary transfer restrictions and foreign currency exchange regulations in the jurisdictions in which our subsidiaries operate. In addition, payment of dividends or distributions from our joint ventures are subject to contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay interest or principal on the notes when due, or to redeem our notes upon a change of control or a fundamental change, and we may not be able to obtain the necessary funds from other sources.

Our notes are guaranteed by certain of our direct and indirect domestic subsidiaries. As of December 31, 2008, our non-guarantor subsidiaries collectively owned approximately 28 percent of our consolidated total assets and held approximately $51 million of our consolidated cash and cash equivalents of approximately $172 million. In 2008, our non-guarantor subsidiaries had drilling and rental revenues of approximately $312 million and a total operating income of approximately $16 million. See Note 5 to the notes to the consolidated financial statements.

ITEM 1A. RISK FACTORS (continued)

Risks Related to our Debt Securities (continued)

The subsidiary guarantees of our notes could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void the subsidiary guarantees.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a guarantee could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:


	•	issued the guarantee with the intent of hindering, delaying or defrauding current or future creditors; or

	•	received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee, and;


	•	was insolvent or rendered insolvent by reason of such incurrence; or

	•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

	•	intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by that guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor, or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:


	•	the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

	•	the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability, including contingent liabilities, on its existing debts, as they become absolute and mature; or

	•	it could not pay its debts as they become due.

We cannot assure what standard a court would apply in determining a guarantor’s solvency and whether or not it would conclude that such guarantor was solvent when it incurred the guarantee.

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

ITEM 1A. RISK FACTORS (continued)

Risks Related to our Debt Securities (continued)

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% 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 any cash payable on 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.

ITEM 1A. RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements contained in this Form 10-K, other than statements of historical facts, are “forward-looking statements” for purposes of these provisions, including any statements regarding:


	•	stability of prices and demand for oil and natural gas;

	•	levels of oil and natural gas exploration and production activities;

	•	demand for contract drilling and drilling related services and demand for rental tools;

	•	our future operating results and profitability;

	•	our future rig utilization, dayrates and rental tools activity;

	•	entering into new, or extending existing, drilling contracts and our expectations concerning when our rigs will commence operations under such contracts;

	•	growth through acquisitions of companies or assets;

	•	construction or upgrades of rigs and expectations regarding when these rigs will commence operations;

	•	capital expenditures for acquisition of rigs, construction of new rigs or major upgrades to existing rigs;

	•	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, 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;

	•	future compliance with covenants under our senior credit facility and indentures for our senior notes; and

	•	organic growth of our operations.

In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses made by our management in light of their experience and perception of historical trends, current conditions, expected future developments and other factors they believe are relevant. Although our management believes that their assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The following factors, as well as any other cautionary language included in this Form 10-K, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our “forward-looking statements:”


	•	worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business;

	•	inability of the Company to access the credit or security markets;

	•	the U.S. economy and the demand for natural gas;

	•	worldwide demand for oil;

ITEM 1A. RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS (continued)


	•	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;

	•	the outcome of our investigation and the parallel investigations by the Securities and Exchange Commission and the Department of Justice into possible violations of U.S. law, including the Foreign Corrupt Practices Act, and the outcome of the internal investigation regarding possible violations of U.S Economic Sanctions primarily related to our operations in Turkmenistan;

	•	adverse environmental events;

	•	adverse weather conditions;

	•	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 in start-up of operations;

	•	changes in competition;

	•	the effect of litigation and contingencies; and

	•	other similar factors (some of which are discussed in documents referred to in this Form 10-K).

Each “forward-looking statement” speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.


ITEM 1B.	*UNRESOLVED STAFF COMMENTS*

None.


ITEM 2.	*PROPERTIES*

We lease office space in Houston for our corporate headquarters. 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

The following table shows, as of December 31, 2008, the locations and drilling depth ratings of our 28 land rigs available for service. 25 of these rigs were under contract, one was available for contract and two were cold stacked as of December 31, 2008.


	Drilling Depth Rating in Feet
	10,000		10,000		Over
Region	or Less		25,000		25000(1)		Total

Asia Pacific		1		7		—		8
CIS		—		6		3		9
Latin America		—		4		5		9
Africa/Middle East		—		2		0		2

Total		1		19		8		28


(1)		One land rig currently in New Iberia yard.

Barge Rigs

The following table shows our 2 international deep drilling barges as of December 31, 2008. Both of these rigs were under contract at December 31, 2008.

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

1,600

2004

20,000


ITEM 2.	*PROPERTIES (continued)*

Barge Rigs (continued)

The following table shows our 15 deep, intermediate, workover and shallow drilling barge rigs located in the U.S. Gulf of Mexico. Five of these barge rigs were under contract and nine were available for contract as of December 31, 2008. 1 barge rig is cold stacked and not currently available for work.


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

Deep drilling:
Rig No. 12		1,500		2006		20,000
Rig No. 15		1,000		2007		15,000
Rig No. 50		2,000		2006		25,000
Rig No. 51		2,000		2008		25,000
Rig No. 54		2,000		2006		25,000
Rig No. 55		2,000		2001		25,000
Rig No. 56		2,000		2005		25,000
Rig No. 72		3,000		2005		30,000
Rig No. 76		3,000		2004		30,000
Rig No. 77		3,000		2006		30,000
Intermediate drilling:
Rig No. 8		1,000		2007		14,000
Rig No. 20		1,000		2005		13,500
Rig No. 21		1,200		2007		14,000
Workover and shallow drilling:
Rig No. 6(1)(2)		700		1995		—
Rig No. 16		1,000		1994		13,500


(1)		Workover rig.


(2)		Cold Stacked


ITEM 2.	*PROPERTIES (continued)*

Barge Rigs (continued)

The following table presents our utilization rates and rigs available for service for the years ended December 31, 2008 and 2007.


	Year Ended December 31,
Transition Zone Rig Data	2008			2007

U.S. barge deep drilling:
Rigs available for service(1)		10.0			10.0
Utilization rate of rigs available for service(2)		85	%		95	%
U.S. barge intermediate drilling:
Rigs available for service(1)		3.0			3.3
Utilization rate of rigs available for service(2)		74	%		70	%
U.S. barge workover and shallow drilling:
Rigs available for service(1)		2.0			3.0
Utilization rate of rigs available for service(2)		41	%		30	%
International barge drilling:
Rigs available for service(1)		2.0			2.0
Utilization rate of rigs available for service(2)		100	%		100	%

U.S. Land Rig Data
Rigs available for service(1):		—			1.6
Utilization rate of rigs available for service(2):		—			55	%

International Land Rig Data
Rigs available for service(1):		28.0			25.8
Utilization rate of rigs available for service(2):		79	%		73	%


(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 for 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 on Form 10-K, which information is incorporated herein by reference.


ITEM 4.	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*

There were no matters submitted to Parker Drilling Company security holders during the fourth quarter of 2008.

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, 2008, there were 1,895 holders of record of Parker Drilling common stock. The following table sets forth the high and low prices per share of Parker Drilling’s common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:


	2008				2007
Quarter	High		Low		High		Low

First	$	7.82	$	5.53	$	9.76	$	7.50
Second		10.17		6.69		12.10		9.40
Third		10.18		7.77		11.65		7.01
Fourth		7.81		2.46		9.07		6.70

Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholders of record. As of January 30, 2009, our common stock was held by 1,888 holders of record and an estimated 27,995 beneficial owners.

Restrictions contained in Parker Drilling’s existing credit agreement and the indentures for the 9.625% Senior Notes and 2.125% Convertible Senior Notes restrict the payment of dividends. We have no present intention to pay dividends on our common stock in the foreseeable future.

We purchased 2,025 shares at an average price of $7.08 during the fourth quarter of 2008 from Parker Drilling personnel to satisfy tax liabilities when portions of restricted stock grants vested.


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, 2008. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in this Form 10-K.


	Year Ended December 31,
	2008(1)			2007			2006(2)			2005(3)			2004
	(Dollars in Thousands, Except Per Share Amounts)

Income Statement Data
Total drilling and rental revenues	$	829,842		$	654,573		$	586,435		$	531,662		$	376,525
Total operating income		59,180			190,983			143,326			115,123			23,867
Equity in loss of unconsolidated joint venture, net of tax		(1,105	)		(27,101	)		—			—			—
Other expense		(23,672	)		(22,081	)		(25,891	)		(44,895	)		(59,423	)
Income tax (expense) benefit		(8,845	)		(37,723	)		(36,409	)		28,584			(15,009	)
Income (loss) from continuing operations		25,558			104,078			81,026			98,812			(50,565	)
Net income (loss)		25,558			104,078			81,026			98,883			(47,083	)
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.23		$	0.95		$	0.76		$	1.03		$	(0.54	)
Net income (loss)	$	0.23		$	0.95		$	0.76		$	1.03		$	(0.50	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.23		$	0.94		$	0.75		$	1.02		$	(0.54	)
Net income (loss)	$	0.23		$	0.94		$	0.75		$	1.02		$	(0.50	)
Balance Sheet Data
Cash and cash equivalents	$	172,298		$	60,124		$	92,203		$	60,176		$	44,267
Marketable securities		—			—			62,920			18,000			—
Property, plant and equipment, net		675,548			585,888			435,473			355,397			382,824
Assets held for sale		—			—			4,828			—			23,665
Total assets		1,213,631			1,076,987			901,301			801,620			726,590
Total long-term debt and capital leases, including current debt		461,073			373,721			329,368			380,015			481,063
Stockholders’ equity		570,404			534,724			459,099			259,829			148,917


(1)		The 2008 results reflect a $100.3 million charge for impairment of goodwill.


(2)		The 2006 results reflect the reversal of an $12.6 million valuation allowance at the end of 2006 and the utilization of $5.4 million of NOL’s (“Net Operating Loss”), both related to Louisiana state net operating loss carryforwards. See Note 7 in the notes to the consolidated financial statements.


(3)		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.


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

OVERVIEW AND OUTLOOK

Summary — We reported solid financial results from operations for the fourth quarter and the year ended 2008. As we anticipated in the third quarter, the effect of the global economic downturn and substantial drop in oil and natural gas prices has primarily been limited to our U.S. Gulf of Mexico (“GOM”) barge business. Utilization of our international rigs was solid during the fourth quarter, and our rental tool business continued to perform at high utilization rates.

The worldwide economy has continued to slow and the global recession continues to widen. We believe that our strategy, performance and diversification have been sound, and have cushioned us from the severity of current market forces, but the nature and extent of any reduction in worldwide demand for drilling as a consequence of a worldwide economic recession and its ultimate effect on our operations is still unknown. We believe that utilization of our international rigs will remain stable in 2009 due to the number of rigs under long term contracts (see Item 1A — Risk Factors), and expect our rental tools business to remain stable as well. Accordingly, we expect our operating performance in these two segments to be better than what current industry trends would indicate. We expect utilization of our GOM barge rigs to remain at low levels for the near future as customers in this market are watching energy prices and waiting for signs of stability before making decisions on spending plans for 2009. However, operators may curtail or delay projects that are dependent upon financing or may experience an inability to pay suppliers and/or service companies, including our Company. We have not experienced material delays in payments from our customers.

Overview — In the fourth quarter of 2008 we took a $100.3 million non-cash goodwill charge primarily as a result of the application of SFAS No. 142 in today’s economic environment. Current accounting rules require a comparison of carrying values of assets including goodwill to current equity is in excess of market capitalization. The write off eliminates all of the goodwill that was recognized at the time we acquired our rental tools business and GOM barge rigs in 1996. This goodwill write off will have no impact on ongoing operations or cash flows. Exclusive of the goodwill charge, we achieved record operating results for the entire year.

In the fourth quarter of 2008 gross margin declined $4.6 million to $47.7 million as compared to $52.3 million for the third quarter of 2008. Our GOM barge business gross margin was $5.5 million for the fourth quarter of 2008, lower than the $14.2 gross margin achieved in the third quarter of 2008. For the year, GOM results, while lower than previous periods, were solid at $54.0 million operating gross margin.

Gross margin for our international drilling operations declined in the fourth quarter of 2008 as compared to the third quarter of 2008 overall by $1.5 million due to $5.2 million related to equipment changes that delayed drilling on our four rig contract in Western Kazakhstan. Gross margins in our other international operations increased by $3.7 million in the fourth quarter of 2008 as compared to the third quarter of 2008, with increases coming from all regions and all areas other than the Karachaganak area in Western Kazakhstan discussed above. Overall, utilization for our international fleet was 87 percent for the fourth quarter of 2008 as compared to 84 percent in the third quarter of 2008.

Rental tools gross margin increased 3.5 percent in the fourth quarter of 2008, as compared to the third quarter of 2008 as a result of increased rental tools sales. Our rental tools segment achieved another year of record operating results.

Gross margin from our contract and engineering services business increased $5.4 million in the fourth quarter of 2008 as compared to the third quarter of 2008, primarily as a result of higher dayrates on our operations and maintenance contracts, and earnings on our rig construction project.

Capital expenditures for 2008 totaled $213.9 million, including major projects of $153.7 million and $58.7 for maintenance and drill pipe. Major projects included completion of new rigs of approximately $62.7 million, construction on AADU rigs and office set up for Alaska operations of $58.3 million,

OVERVIEW AND OUTLOOK (continued)

Overview (continued)

$21.2 million upgrades and refurbishments for GOM barges and $11.6 million for equipment and property for our rental tools business. Cash expenditures totaled $197.1 million, with an additional $16.8 million in accrued expenditures.

Outlook — We expect solid earnings from our international operations throughout 2009. We expect increases in earnings for our four rig contract in Kazakhstan as drilling resumed in late December 2008 for one rig, February 2009 for two and in early March 2009 for the last rig. Two of these rigs are under contract through mid 2010 and the other two through mid 2011. In Mexico we have eight rigs drilling, two of which are under contract through mid 2009, four of which are under contract through early to mid 2010, one through the third quarter of 2012, and one with a recent three well extension which is expected to keep the rig operating throughout 2009. Current utilization of our international rigs is at 74 percent.

Our rental tools operations should remain stable as we anticipate many of our major oil company customers will continue to operate at current levels, primarily in deepwater E&P projects. In fact, several of our largest customers have indicated that their drilling programs will continue at prior year levels. In addition, we expect the development of unconventional resource plays to continue through 2009 as operators ensure that they satisfy their drilling obligations under oil and gas leases in these areas, particularly in the Haynesville Shale area, which are generally short term and expensive.

We also expect solid results from our project management and engineering services segment, including increased earnings from our construction contract segment in 2009. These increased earnings are due primarily to the BP Liberty construction contract as we progress toward the completion of the construction and delivery of the rig which is targeted for the first quarter 2010. Earnings on this project are based on percentage of completion.

Current U.S. GOM barge utilization is 20% with only three rigs drilling. Barge 76 will resume operation in early March 2009 after the completion of shipyard refurbishments. We are in discussion with other customers regarding drilling prospects which could be awarded as early as March 2009. However, we currently have no assurance that GOM utilization will increase as this is dependent upon the factors noted above. (See also Risk Factors in Item 1A).

Capital expenditures for 2009 are projected to be approximately $180 - $200 million which includes approximately $125 — $135 million for major projects and $30 — $35 million for maintenance and drill pipe spending of which $25 — $30 million is for Quail. Major projects are comprised primarily of $100 million to complete the Alaskan AADU (“Alaskan Arctic Drilling Units”) rigs and facilities and approximately $25 million for upgrades for our barge rig operating in the Caspian Sea.

On September 12, 2008 we drew down $10 million on our revolving credit facility, and on October 16 and 17, 2008, we drew down an additional aggregate amount of $48 million. The funds will be used over the next 12 months to fund the construction of two new-build rigs to perform the five year drilling contract in Alaska based on the executed letter of intent with BP.

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

We recorded net income of $25.6 million for the year ended December 31, 2008 which included a goodwill write-off of $100.3 million, as compared to net income of $104.1 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, project management and engineering services, construction contract and rental tools 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

OVERVIEW AND OUTLOOK (continued)

Overview (continued)

such, 2007 segment information has been recasted 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.

RESULTS OF OPERATIONS (continued)

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


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

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

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

Operating gross margin:
U.S. drilling gross margin excluding depreciation and amortization(1)	$	89,202		51	%	$	130,911		58	%
International drilling gross margin excluding depreciation and amortization(1)		93,687		29	%		59,227		28	%
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	%		—
Rental tools gross margin excluding depreciation and amortization(1)		104,506		61	%		83,654		61	%
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 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:

RESULTS OF OPERATIONS (continued)


					Project
					Management
			International		and		Construction
	U.S. Drilling		Drilling		Engineering		Contract		Rental Tools
Year Ended December 31, 2008	(Dollars in Thousands)

Operating gross margin(2)	$	53,964	$	41,786	$	18,470	$	2,597	$	74,689
Depreciation and amortization		35,238		51,901		—		—		29,817

Operating gross margin excluding depreciation and amortization	$	89,202	$	93,687	$	18,470	$	2,597	$	104,506

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

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


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

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. Also in 2007 we had two land rigs drilling in the U.S. that historically operate in our international land segment. These rigs contributed $11.3 million in revenues 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.

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 and a dayrate increase for our barge rig operating in Mexico. Revenues in the CIS region increased by $63.7 million primarily attributable 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 offset by lower utilization of our two rigs in Colombia in 2008, resulting in a decrease of $22.2 million as compared to 2007.

In our Asia Pacific region, revenues decreased $8.2 million due mainly to completion of our contract within Bangladesh for Rig 225 in March 2007 ($3.5 million), lower utilization (50%) in Papua New Guinea ($15.6 million) being 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 the year ended 2008 compared to 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

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

Karachaganak area of Kazakhstan and operation of Rig 230 in Turkmenistan were the main drivers of the $24.1 million 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.

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 was due to higher dayrates and $11.8 million 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 do not incur depreciation and amortization, and as such, gross margin for this segment increased $5.7 million in the current period as compared to the prior period. 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 which costs-to-date compared to projected total costs are used to determine the percent complete (cost to cost method).

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.

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

Other Financial Data

Gain on asset dispositions was $2.7 million, a decrease of $13.7 million 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 relatively unchanged as compared to the same period of 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 as compared to the year ended 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

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

the notes to the consolidated financial statements. These fees included upgrades to our compliance process and code of conduct.

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-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.

Income tax expense was $8.8 million for the year ended December 31, 2008, as compared to income tax expense of $37.7 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 — Kazakhstan Tax Case), 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, 2007 Compared with Year Ended December 31, 2006

We recorded net income of $104.1 million for the year ended December 31, 2007, as compared to net income of $81.0 million for the year ended December 31, 2006. Operating gross margin was $200.7 million for the year ended December 31, 2007 as compared to $167.5 million for the year ended December 31, 2006. Gain on disposition of assets for 2007 was $16.4 million as compared to $7.6 million in the comparable period in 2006.

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

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


	Year Ended December 31,
	2007					2006
	(Dollars in Thousands)

Revenues:
U.S. drilling	$	225,263		34	%	$	191,225		33	%
International drilling		213,566		33	%		184,280		31	%
Project management and engineering services		77,713		12	%		88,936		15	%
Rental tools		138,031		21	%		121,994		21	%

Total revenues	$	654,573		100	%	$	586,435		100	%

Operating gross margin:
U.S. drilling gross margin excluding depreciation and amortization(1)	$	130,911		58	%	$	107,689		56	%
International drilling gross margin excluding depreciation and amortization(1)		59,227		28	%		39,964		22	%
Project management and engineering services gross margin excluding depreciation and amortization(1)		12,732		16	%		13,616		15	%
Rental tools gross margin excluding depreciation and amortization(1)		83,654		61	%		75,540		62	%
Depreciation and amortization		(85,803	)				(69,270	)

Total operating gross margin(2)		200,721					167,539
General and administrative expense		(24,708	)				(31,786	)
Provision for reduction in carrying value of certain assets		(1,462	)				—
Gain on disposition of assets, net		16,432					7,573

Total operating income	$	190,983				$	143,326


(1)		Operating gross margins, excluding depreciation and amortization, are computed as revenues less operating expenses, excluding depreciation and amortization expense; operating 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 operating gross margin. Management

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)


		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		and
	U.S. Drilling		Drilling		Engineering		Rental Tools
	(Dollars in Thousands)

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

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

Year Ended December 31, 2006
Operating gross margin(2)	$	83,296	$	13,923	$	13,616	$	56,704
Depreciation and amortization		24,393		26,041		—		18,836

Operating gross margin excluding depreciation and amortization	$	107,689	$	39,964	$	13,616	$	75,540


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

U.S. Drilling Segment

Revenues for the U.S drilling segment increased $34.0 million to $225.3 million for 2007 as compared to 2006. The increased revenues were primarily due to a $46.0 million increase for deep drilling barges, as a result of a full year of operations for ultra-deep Barge Rig 77, 95 percent fleet utilization in 2007 versus 81 percent in 2006 and a 12 percent increase in dayrates. These increases were partially offset by a $15.9 million decrease in revenues for intermediate and workover barges due primarily to the sale of workover Barge Rigs 9 and 26 (see Note 2 to the consolidated financial statements in Item 8 of this Form 10-K). Barge Rig 12 was undergoing an upgrade from workover to deep drilling status until late May 2006 and newly constructed Barge Rig 77 began operations in December 2006. During 2007 we also had two repositioned international land rigs operating in the U.S. market which contributed $4.2 million to the increase in U.S. drilling segment revenues.

Average dayrates for the deep drilling barge rigs increased approximately $5,400 per day in 2007 as compared to 2006. As a result of higher dayrates and additional revenue days on the deep drilling barge rigs, the addition of two land rigs, gross margins, excluding depreciation and amortization, increased $23.2 million to $130.9 million. This increase includes a $1.1 million decrease for the two land rigs as a result of expenses incurred in moving the rigs out of the U.S. after completion of wells in early 2007.

International Drilling Segment

International drilling revenues increased $29.3 million to $213.6 million during the year ended December 31, 2007. Of this increase, $42.4 million is related to an increase in international land drilling revenues, offset by a $13.1 million decrease in revenues from offshore operations due primarily to the sale of our barge rigs in Nigeria in the third quarter of 2006.

In our Americas region, drilling revenues in Mexico increased $10.8 million to $37.5 million due to higher dayrates under the new contracts entered into in 2007 and higher utilization. In Colombia, revenues were $36.1 million higher in 2007 than in 2006, as Rig 268 commenced operation on December 27, 2006 and Rig 271 was mobilizing at the end of 2006, whereas both rigs operated most of 2007.

Revenues in the CIS decreased by $7.5 million as a result of:


	•	completion of the two-rig, TCO contract in 2006 ($28.7 million);

	•	the release of our three rigs in Turkmenistan ($7.9 million) during the third quarter of 2006.

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)


	•	A decrease in reimbursable revenues relating to our barge rig operating in the Caspian Sea ($1.6 million)

These decreases were partially offset by:


	•	an $18.5 million increase in the Karachaganak area of Kazakhstan, where Rig 107 operated all year in 2007 (the rig was released in late December 2005 from the TCO contract and commenced operations at the end of March 2006) and the addition of Rigs 249 and 258 (from the TCO contract), both of which began drilling in the third quarter of 2007; and

	•	increases related to the full-year operation of Rig 236, which began drilling in western Kazakhstan in late 2006 ($12.5 million).

In our Asia Pacific region, revenues decreased $4.4 million due mainly to completion of contracts in Bangladesh for Rig 225 ($8.7 million) and for two of our rigs in New Zealand ($1.7 million), partially offset by increased utilization in Papua New Guinea ($5.4 million).

Gross margin, excluding depreciation and amortization, for international operations increased by $19.3 million. In Mexico, gross margin, excluding depreciation and amortization, improved by $17.6 million due to higher dayrates under new contracts and to lower expenses in 2007, as 2006 included costs to close down operations and relocate the seven of the eight rigs outside Mexico. In Colombia, gross margin, excluding depreciation and amortization, increased by $16.2 million as two rigs drilled most of 2007, compared to virtually no rigs operating in Colombia in the comparable period of 2006. In the Karachaganak area of Kazakhstan, gross margin, excluding depreciation and amortization, increased $8.8 million as two rigs operated all of the period of 2007, compared to one rig in the comparable period of 2006 and also as a result of pre-mobilization standby and operating revenues for Rigs 249 and 258 that moved into the field in 2007. Rig 236, also operating in Kazakhstan, contributed an increase of $1.5 million for the period of 2007, as this rig was not working in the region in the comparable period in 2006. Gross margin for our barge rig operating in the Caspian Sea increased $1.9 million, as a result of lower costs

The increases were partially offset by $8.1 million in losses incurred in our Africa Middle East region as our Libya operations incurred a $3.8 million loss mainly due to start up costs being written off as a result of an abrupt contract termination by our customer after completion of one well and in Algeria where excessive downtime and delayed start-ups contributed to a loss of $4.4 million for the year and the sale of the Nigeria barge rigs in 2006. Other gross margin decreases related to the completion of contract wells under our TCO contract, the release of rigs in Turkmenistan, and relocation of Rig 122 and 256 to U.S. operations, all of which occurred in 2006.

Project Management and Engineering Services Segment

Revenues for this segment decreased $11.2 million to $77.7 million during the year ended 2007 as compared to 2006. This decrease was the result of a decline in our Sakhalin Island operations ($2.8 million primarily related to lower reimbursable revenues and the completion of a water reinjection well project in July 2006) and our Papua New Guinea (“PNG”) contracts ($7.5 million as our operations there began winding down during 2007). These decreases were partially offset by revenues of $5.9 million for our engineering services related to our BP Liberty project which began in 2007. Project management and engineering services do not incur depreciation and amortization, as such, gross margin for this segment decreased $0.9 million in the current period as compared to the prior period. Decreases in our Kuwait ($0.9 million) and our aforementioned PNG operations ($2.3 million) were partially offset by a positive margin in our BP Liberty services ($1.8 million).

RESULTS OF OPERATIONS (continued)

Rental Tools Segment

Rental tools revenues increased $16.0 million to $138.0 million during the year ended December 31, 2007 as compared to 2006. The increase was due primarily to an increase in rental revenues of $7.3 million from our Texarkana operations net of reductions at our Odessa facility for customers formerly served by that location, $1.7 million from international rentals, $9.0 million from our Evanston, Wyoming operations and $3.6 million from our New Iberia location, partially offset by a decline of $5.5 million from our Victoria, Texas operation.

Revenues increased primarily due to higher demand and higher rental tool sales. Rental tools gross margins, excluding depreciation and amortization, increased $8.2 million to $83.7 million for the current period as compared to 2006. Gross margin percentage, excluding depreciation and amortization, decreased to 61 percent in the current period as compared to 62 percent in 2006.

Other Financial Data

Gain on asset dispositions increased by $8.9 million, due primarily to the gain on the sale of the two workover barge rigs in the first quarter of 2007. Interest expense declined $6.4 million during the year ended December 31, 2007 as compared to 2006 due to lower average rates on our outstanding debt and capitalization of $6.2 million in interest on rig construction projects in 2007. There was $3.6 million of capitalized interest for the year ended December 31, 2006. Interest income decreased $1.5 million when compared to 2006 due to lower levels of cash available for investment. Our 2007 equity loss related to our 50 percent-owned joint venture in Saudi Arabia was $27.1 million, consisting of $13.8 million in accrued liquidated damages, a $9.8 operating loss and a $3.5 million reserve for advances to the joint venture. General and administration expense decreased $7.1 million as compared to the year ended 2006 as a result of a change, in 2007 going forward in our method of estimating the amount of corporate shared services costs allocable to operations. The current method is based on a third party study of actual shared service time spent on each operation, whereas the previous method was less precise and based on each operation’s portion of total revenues.

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-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 and for the year ended December 31, 2006, we recognized a minimal change 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.

Income tax expense was $37.7 million for the year ended December 31, 2007 as compared to $36.4 million for the year ended December 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

As of December 31, 2008, we had cash and cash equivalents of $172.3 million, an increase of $112.2 million from December 31, 2007. The following table provides a summary for the last three years:


	2008			2007			2006
	In Thousands

Operating Activities	$	220,318		$	74,276		$	166,868
Investing activities		(196,607	)		(152,889	)		(194,651	)
Financing activities		88,463			46,534			59,810
Net change in cash and cash equivalents		112,174			(32,079	)		32,027

LIQUIDITY AND CAPITAL RESOURCES (continued)

Liquidity (continued)

Operating Activities

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, an increase in depreciation, and an impairment of goodwill. 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.

Cash flows from operating activities were $74.3 million for 2007 compared to $166.9 million for 2006. The decrease in cash provided from operating activities is due to increased working capital requirements and the net effect of an increase to net income, and an increase in depreciation. Higher working capital requirements of $157.7 million were principally driven by an increase in accounts receivable and a reduction in accrued income taxes including a $26.4 million tax payment to Kazakhstan (see Note 7 income taxes) compared to changes in 2006. Depreciation in 2007 increased to $85.8 million compared to $69.3 million in 2006 due to additional rigs being placed into service, major upgrades to existing rigs and the expansion of our rental tools business.

Investing Activities

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 from assets sales and insurance proceeds.

Cash flows used in investing activities were $152.9 million for 2007. Our primary uses of cash were $242.1 million for capital expenditures and a $5.0 million investment in our Saudi joint venture. Major capital expenditures for the period included $75.6 million on construction of new land rigs, $62.0 million for tubulars and other rental tools for the expansion of Quail Tools and $11.4 million on rebuilding Rig 247. Primary sources of cash were net proceeds of $62.9 million from the sale and purchase of marketable securities, proceeds of $20.5 million from the sale of two workover barge rigs and insurance proceeds of $7.8 million relating to Rig 247.

Our estimated expenditures for 2009 will primarily be directed to our two new Alaska rigs. Additional spending to maintain current operations will comprise the remaining portion of our expenditures and any discretionary spending will be evaluated based upon adequate return requirements and available liquidity. We believe that we have sufficient cash and available liquidity to sustain operations and fund our capital expenditures for 2009, 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” regarding additional risk related to our business.

Financing Activities

Cash flows from financing activities were $88.5 million for 2008. Our primary sources of cash include a net drawdown on our 2007 and 2008 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.

Cash flows from financing activities were $46.5 million for 2007. Our primary sources of cash include $109.2 million from the issuance of our 2.125 percent Convertible Senior Notes; net of issuance costs and hedge and warrant transactions, a drawdown of $20.0 million on our 2007 Credit Facility and $15.5 million

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activities (continued)

from stock options exercised. Our primary uses of cash was $100.0 million for the redemption of all our outstanding Senior Floating Rate Notes

2008 Credit Facility

On May 15, 2008 we 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 the Company’s domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed a guaranty. 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, 2008 our Consolidated Leverage Ratio was 1.67 to 1 compared to the maximum permitted 4.00 to 1; our Consolidated Interest Coverage Ratio was 11.24 to 1 compared to the minimum permitted 2.50 to 1 and our Consolidated Senior Secured Leverage Ratio was 0.39 to 1 compared to the maximum permitted 1.50 to 1. At this time the company does not anticipate triggering any of these covenants during 2009.

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, 2008, there were $12.8 million in letters of credit outstanding, $50.0 million outstanding on the Term Loan Facility and $58.0 million outstanding on 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 represents 94 percent of the capacity of the Revolving Credit Facility (which also reflects 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). Subsequent to year end, Lehman Commercial Paper, Inc. assigned its obligations under the 2008 Credit Facility to Trustmark National Bank. On the closing date, January 30, 2009, Trustmark National Bank fully funded Lehman Commercial Paper, Inc.’s commitments, 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. The Company expects to use the drawn amounts over the next twelve months to fund construction of two new rigs for work in Alaska. Although the credit crisis 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 percent Convertible Senior Notes

On July 5, 2007, we 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.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activities (continued)


	•	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 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 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.

	•	Over-allotment Provision — The initial offering was for $115 million aggregate principal amount with an over-allotment provision to allow the underwriters an option to purchase an additional $10 million. The option was in fact, exercised for the entire $10 million on the same date on which the notes were issued, and therefore was never outstanding.

	•	Settlement Feature — Upon conversion, we will pay shares of our common stock and cash, 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, 2008, none of the conditions allowing holders of the Senior Notes to convert had been met.

Concurrently with the issuance of the Convertible Senior 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 issue and/or pay to the holders of the Senior Convertible 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: 1) the last day on which the convertible notes remain outstanding, and 2) the maturity date of the convertible notes.

The convertible notes are a legal form debt and 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 as outlined in EITF No. 00-19, “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

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activities (continued)

classified in stockholders’ equity and are solely indexed to our own common stock, they are not accounted for as derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

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 call our outstanding 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 pursuant to a redemption notice dated August 17, 2007 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 expires in September 2012. The 2007 Credit Facility is 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.

The 2007 Credit Facility was 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 were available under the 2007 Credit Facility subject to a borrowing base limitation based on 85 percent of eligible receivables plus a value for eligible rental tools equipment. The 2007 Credit Facility called for a borrowing base calculation only when the 2007 Credit Facility had outstanding loans, including letters of credit, totaling at least $40.0 million. As of December 31, 2008, there were $12.8 million in letters of credit outstanding and $20.0 million of outstanding loans.

Other Liquidity

On January 23, 2006 we completed the public offering of 8,900,000 shares of our common stock at a price of $11.23 per share, for total net proceeds of $99.9 million before expenses, but after underwriter discount. Proceeds from this offering were used for capital expansions, including rig upgrades, new rig construction and expansion of our rental tools business.

On September 8, 2006 we redeemed $50.0 million face value of our Senior Floating Rate Notes pursuant to a redemption notice dated August 8, 2006 at the redemption price of 102.0 percent. Proceeds from the sale of our Nigerian barge rigs and cash on hand were used to fund the redemption.

Our principal amount of long-term debt, including current portion, is $458.0 million as of December 31, 2008, which consists of:


	•	$125.0 million aggregate principal amount of Convertible Senior Notes bearing interest at a rate of 2.125 percent, which are due July 15, 2012;

	•	$225.0 million aggregate principal amount of 9.625 percent Senior Notes, which are due October 1, 2013 plus an associated $3.1 million in unamortized debt premium; and,

	•	$108.0 million drawn against our 2008 Credit Facility, including $58.0 million on our Revolving Credit Facility and $50.0 million on our Term Loan Facility, $6.0 million of which is classified as short term.

As of December 31, 2008, we had approximately $181.5 million of liquidity. This liquidity was comprised of $172.3 million of cash and cash equivalents on hand and $9.2 million of availability under the credit facility. We do not have any unconsolidated special-purpose entities, off-balance sheet financing

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activities (continued)

arrangements nor guarantees of third-party financial obligations. We have no energy, commodity foreign currency or interest rate derivative contracts at December 31, 2008.

The following table summarizes our future contractual cash obligations as of December 31, 2008:


			Less than						More than
	Total		1 Year		Years 2 - 3		Years 4 - 5		5 Years
	(Dollars in Thousands)

Contractual cash obligations:
Long-term debt — principal(1)	$	400,000	$	6,000	$	24,000	$	370,000	$	—
Long-term debt — interest(1)		132,387		29,921		58,110		44,356		—
Operating leases(2)		8,646		4,689		2,864		1,093		—
Purchase commitments(3)		34,319		34,319		—		—		—

Total contractual obligations	$	575,352	$	74,929	$	84,974	$	415,449	$	—

Commercial commitments:
Long-term debt —
Revolving credit facility(4)	$	58,000	$	—	$	—	$	58,000	$	—
Standby letters of credit(4)		12,823		12,823		—		—		—

Total commercial commitments	$	70,823	$	12,823	$	—	$	58,000	$	—


(1)		Long-term debt includes the principal and interest cash obligations of the 9.625 percent Senior Notes and the 2.125 percent Convertible Notes. The remaining unamortized premium of $3.1 million is not included in the contractual cash obligations schedule.


(2)		Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.

(3)		We have purchase commitments outstanding as of December 31, 2008, related to rig upgrade projects and new rig construction.

(4)		We have an $80.0 million revolving credit facility. As of December 31, 2008, $58.0 million has been drawn down and $12.8 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $9.2 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 of variable-to-fixed interest rate swaps, did not meet the hedge criteria in SFAS No. 133 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/or 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 U.S. Gulf of Mexico for major and independent oil and gas companies. Business activity is primarily dependent on the

OTHER MATTERS (continued)

Business Risks (continued)

exploration and development activities of the companies that make up our customer base. See Item 1A, Risk Factors, for a detailed statement of Risk Factors 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, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.

Impairment of Property, Plant and Equipment. We periodically evaluate our property, plant and equipment to ensure that the net carrying value is not in excess of the net realizable value. We review our property, plant and equipment for impairment 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 SFAS No. 144, “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.

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 mentioned in “Impairment of Goodwill” below, we tested our long-lived assets for impairment as of December 31, 2008 and determined there was no asset impairment required.

Impairment of Goodwill. We periodically assess whether the excess of cost over net assets acquired (goodwill) is impaired based generally on the estimated fair value of that operation. If the estimated fair value is in excess of the carrying value of the operation, no further analysis is performed. If the fair value of each operation to which goodwill has been assigned is less than its carrying value, we deduct the fair value of the tangible and intangible assets and compare the residual amount to the carrying value of the goodwill to determine if impairment should be recorded. Changes in dayrate and utilization assumptions used in the fair value calculations could result in fair value estimates that are below carrying value, resulting in an impairment of goodwill. We also test for impairment based on other events or changes in circumstances that may indicate a reduction in the fair value of a reporting unit below its carrying value.

As required by SFAS No. 142, “Goodwill and Other Intangible Assets,” we perform an annual impairment analysis of goodwill at each year end. Our annual impairment tests of goodwill for 2006 and 2007 indicated

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

that the fair value of operations to which goodwill relates exceeded the carrying values as of December 31, 2006 and 2007; accordingly, no impairments were recorded. In 2008, we wrote off all goodwill as the carrying value of the reporting units to which goodwill related, was in excess of fair value as calculated under SFAS No. 142. The 2008 write off was driven primarily by adverse market conditions that reduced the Company’s equity market capitalization below its Shareholders’ Equity (see Note 3, in the Notes to the Consolidated Financial Statements).

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, there is no assurance that such insurance or indemnification agreements will 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 claims and health benefits. 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.

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

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 NOL (“Net Operating Loss”) 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 SFAS No. 109 “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.

Our accounting policy for income taxes is also affected by FIN 48, “Accounting for Uncertainty in Income Taxes,” which we adopted January 1, 2007. This interpretation requires management to make estimates and assumptions that affect 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 using the cost-to-cost method.

Recent Accounting Pronouncements

See Note 17 in the notes to our consolidated financial statements.


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

Interest Rate Risk

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-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 and for the year ended December 31, 2006 we recognized a minimal change 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.

Long-Term Debt

The estimated fair value of our $225.0 million principal amount of 9.625% Senior Notes due 2013, based on quoted market prices, was $174.4 million at December 31, 2008. The estimated fair value of our $125.0 million principal amount of Convertible Senior Notes due 2012 was $80.3 million on December 31, 2008.

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 as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2008. We also have audited Parker Drilling Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Parker Drilling Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. The accompanying consolidated financial statements of Parker Drilling Company and subsidiaries as of December 31, 2006 and for the year then ended, were audited by other auditors whose report thereon dated February 28, 2007, expressed an unqualified opinion on those statements, before the recasted adjustments described in Note 1 and Note 12 to the consolidated financial statements.

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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also in our opinion, Parker Drilling Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Parker Drilling Company:

In our opinion, the consolidated statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2006, before the effects of the adjustments to retrospectively reflect the change in the composition of reportable segments described in Note 12, present fairly, in all material respects, the results of operations and cash flows of Parker Drilling Company and its subsidiaries for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America (the 2006 financial statements before the effects of the adjustments discussed in Note 12 are not presented herein). In addition, in our opinion, the financial statement schedule for the year ended December 31, 2006 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit, before the effects of the adjustments described above, of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the change in the composition of reportable segments described in Note 12 and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have properly applied. Those adjustments were audited by other auditors.

PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2007

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Data)


	Year Ended December 31,
	2008			2007			2006

Revenues:
U.S. drilling	$	173,633		$	225,263		$	191,225
International drilling		325,096			213,566			184,280
Project management and engineering services		110,147			77,713			88,936
Construction contract		49,412			—			—
Rental tools		171,554			138,031			121,994

Total revenues		829,842			654,573			586,435

Operating expenses:
U.S. drilling		84,431			94,352			83,536
International drilling		231,409			154,339			144,316
Project management and engineering services		91,677			64,981			75,320
Construction contract		46,815			—			—
Rental tools		67,048			54,377			46,454
Depreciation and amortization		116,956			85,803			69,270

Total operating expenses		638,336			453,852			418,896

Total operating gross margin		191,506			200,721			167,539

General and administration expense		(34,708	)		(24,708	)		(31,786	)
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			7,573

Total operating income		59,180			190,983			143,326

Other income and (expense):
Interest expense		(24,533	)		(25,157	)		(31,598	)
Change in fair value of derivative positions		—			(671	)		40
Interest income		1,405			6,478			7,963
Loss on extinguishment of debt		—			(2,396	)		(1,912	)
Equity in loss of unconsolidated joint venture, net of taxes		(1,105	)		(27,101	)		—
Minority interest		—			(1,000	)		(229	)
Other		(544	)		665			(155	)

Total other income and (expense)		(24,777	)		(49,182	)		(25,891	)

Income before income taxes		34,403			141,801			117,435

Income tax expense (benefit):
Current tax expense (benefit)		(1,539	)		17,602			20,654
Deferred tax expense		10,384			20,121			15,755

Total income tax expense		8,845			37,723			36,409

Income from continuing operations		25,558			104,078			81,026
Discontinued operations		—			—			—

Net income	$	25,558		$	104,078		$	81,026

Basic earnings per share:
Income from continuing operations	$	0.23		$	0.95		$	0.76
Discontinued operations	$	—		$	—		$	—
Net income	$	0.23		$	0.95		$	0.76
Diluted earnings per share:
Income from continuing operations	$	0.23		$	0.94		$	0.75
Discontinued operations	$	—		$	—		$	—
Net income	$	0.23		$	0.94		$	0.75
Number of common shares used in computing earnings per share:
Basic		111,400,396			109,542,364			106,552,015
Diluted		112,430,545			110,856,694			108,138,384

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)


	December 31,
ASSETS	2008		2007

Current assets:
Cash and cash equivalents	$	172,298	$	60,124
Accounts and notes receivable, net of allowance for bad debts of $3,169 in 2008 and $3,152 in 2007		186,164		166,706
Rig materials and supplies		30,241		24,264
Deferred costs		7,804		7,795
Deferred income taxes		9,735		9,423
Other tax assets		40,924		32,532
Other current assets		26,125		22,339

Total current assets		473,291		323,183

Property, plant and equipment, at cost:
Drilling equipment		960,472		837,287
Rental tools		210,151		188,140
Buildings, land and improvements		27,340		23,224
Other		45,552		44,293
Construction in progress		144,721		121,023

		1,388,236		1,213,967
Less accumulated depreciation and amortization		712,688		628,079

Property, plant and equipment, net		675,548		585,888
Other assets:
Goodwill		—		100,315
Rig materials and supplies		7,219		1,925
Debt issuance costs		7,285		7,324
Deferred income taxes		30,867		40,121
Investment in and advances to unconsolidated joint venture		—		(4,353	)
Other assets		19,421		22,584

Total other assets		64,792		167,916

Total assets	$	1,213,631	$	1,076,987

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Continued)
(Dollars in Thousands)


	December 31,
LIABILITIES AND STOCKHOLDERS’ EQUITY	2008			2007

Current liabilities:
Current debt	$	6,000		$	20,000
Accounts payable		77,814			36,062
Accrued liabilities		62,584			51,290
Accrued income taxes		12,130			16,828

Total current liabilities		158,528			124,180

Long-term debt		455,073			353,721
Other long-term liabilities		21,396			56,318
Long-term deferred tax liability		8,230			8,044
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 113,455,821 shares (111,915,773 shares in 2007)		18,910			18,653
Capital in excess of par value		603,731			593,866
Accumulated deficit		(52,237	)		(77,795	)

Total stockholders’ equity		570,404			534,724

Total liabilities and stockholders’ equity	$	1,213,631		$	1,076,987

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	25,558		$	104,078		$	81,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		116,956			85,803			69,270
Impairment of goodwill		100,315			—			—
Amortization of debt issuance and premium		1,237			845			764
Loss on extinguishment of debt		—			1,396			910
Gain on disposition of assets		(2,697	)		(16,432	)		(7,573	)
Provision for reduction in carrying value of certain assets		—			1,462			—
Deferred tax expense		10,384			20,121			15,755
Equity loss in unconsolidated joint venture		1,105			27,101			—
Expenses not requiring cash		9,363			10,597			9,674
Change in assets and liabilities:
Accounts and notes receivable		(14,958	)		(60,209	)		(3,456	)
Rig materials and supplies		(11,271	)		(4,945	)		(2,605	)
Other current assets		(15,737	)		(12,720	)		34,420
Accounts payable and accrued liabilities		(238	)		(19,728	)		(28,143	)
Accrued income taxes		(2,404	)		(48,998	)		(3,101	)
Other assets		2,705			(14,095	)		(73	)

Net cash provided by operating activities		220,318			74,276			166,868

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(197,070	)		(242,098	)		(195,022	)
Proceeds from the sale of assets		4,512			23,445			50,790
Proceeds from insurance claims		951			7,844			4,501
Investment in unconsolidated joint venture		(5,000	)		(5,000	)		(10,000	)
Purchase of marketable securities		—			(101,075	)		(198,120	)
Proceeds from sale of marketable securities		—			163,995			153,200

Net cash used in investing activities		(196,607	)		(152,889	)		(194,651	)

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Continued)
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	$	50,000		$	125,000		$	—
Principal payments under debt obligations		(35,000	)		(100,000	)		(50,000	)
Proceeds from revolver draw		73,000			20,000			—
Purchase of call options		—			(31,475	)		—
Sale of common stock warrants		—			20,250			—
Proceeds from common stock offering		—			—			99,947
Payment of debt issuance costs		(1,846	)		(4,618	)		—
Proceeds from stock options exercised		1,969			15,455			7,537
Excess tax benefit from stock-based compensation		340			1,922			2,326

Net cash provided by financing activities		88,463			46,534			59,810

Net increase (decrease) in cash and cash equivalents		112,174			(32,079	)		32,027
Cash and cash equivalents at beginning of year		60,124			92,203			60,176

Cash and cash equivalents at end of year	$	172,298		$	60,124		$	92,203

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	27,192		$	27,439		$	30,898
Income taxes	$	45,615		$	74,801		$	21,566

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Dollars and Shares in Thousands)


								Unamortized			Accumulated
					Capital in			Restricted			Other
			Common		Excess of			Stock Plan			Comprehensive		Accumulated
	Shares		Stock		Par Value			Compensation			Income (Loss)		Deficit

Balances, December 31, 2005		97,836		16,306		456,135			(4,212	)		—		(208,400	)
Adoption of FAS 123R		—		—		(4,212	)		4,212			—		—
Activity in employees’ stock plans		2,414		431		9,031			—			—		—
Common stock offering		8,900		1,483		98,464			—			—		—
Excess tax benefit from stock based compensation		—		—		2,326			—			—		—
Amortization of restricted stock plan compensation		—		—		6,509			—			—		—
Net income (total comprehensive income of $81,026)		—		—		—			—			—		81,026

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			—			—		—
Net income (total comprehensive income of $104,078)		—		—		—			—			—		104,078

Balances, December 31, 2007		111,916	$	18,653	$	593,866		$	—		$	—	$	(77,795	)
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 $25,558)		—		—		—			—			—		25,558

Balances, December 31, 2008		113,456	$	18,910	$	603,731		$	—		$	—	$	(52,237	)

See accompanying notes to the consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


Note 1 —	Summary of Significant Accounting Policies

Consolidation — The consolidated financial statements include the accounts of Parker Drilling Company (“Parker Drilling”) and all of its majority-owned subsidiaries, 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. Parker Drilling currently consolidates one company in which a subsidiary of Parker Drilling has a 50 percent stock ownership. A subsidiary of Parker Drilling also has a 50 percent interest in one other company which is accounted for under the equity method as the Company’s interest in the entity does not meet the consolidation criteria described above.

Operations — The Company provides land and offshore contract drilling services and rental tools on a worldwide basis to major, independent and national oil and gas companies and integrated service providers. At December 31, 2008, the Company’s marketable rig fleet consists of 17 barge drilling and workover rigs, and 28 land rigs. The Company specializes in the drilling of deep and difficult wells, drilling in remote and harsh environments, drilling in transition zones and offshore waters, and in providing specialized rental tools. The Company also provides a variety of project management and engineering services.

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. Mobilization fees received and related mobilization costs incurred are deferred and amortized over the contract term.

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, we were awarded a cost reimbursable, fixed fee 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 front end engineering design of the rig. Total cost of the construction phase is currently expected to be approximately $212 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 the cost-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, 2008, a net receivable (construction costs less progress payments) of $2.1 million is included in other current assets.

Reimbursable Costs — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $53.3 million, $25.4 million and $35.9 million during the years ended December 31, 2008, 2007 and 2006, 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 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 1 —	Summary of Significant Accounting Policies (continued)


	December 31,
	2008			2007
	(Dollars in Thousands)

Trade	$	189,266		$	169,811
Employee(1)		67			47
Allowance for doubtful accounts(2)		(3,169	)		(3,152	)

Total receivables	$	186,164		$	166,706


(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, 2008, 2007 and 2006 are reported on Schedule II — Valuation and Qualifying Accounts.

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. The depreciable lives for land drilling equipment approximate 15 years. The depreciable lives for offshore drilling equipment generally range up to 15 years. The depreciable lives for certain other equipment, including drill pipe and rental tools, range from three to seven years. Depreciable lives for buildings and improvements range from 10 to 30 years. When assets are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any gain or loss is included in operations. 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 cost capitalized during 2008, 2007 and 2006 related to the construction of rigs totaled $5.1 million, $6.2 million and $3.6 million, respectively.

Goodwill — In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” goodwill is assessed for impairment on at least an annual basis. 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 12 months are classified as current.

Other Long-Term Liabilities — Included in this account are an estimate of workers’ compensation liability, deferred tax liability and deferred mobilization fees which are not expected to be paid or recognized within the next year.

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 provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes (FIN 48)” as of January 1, 2007.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 1 —	Summary of Significant Accounting Policies (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, 2008 and 2007, the Company had deposits in domestic banks in excess of federally insured limits of approximately $126.3 million and $48.2 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2008 and 2007 of $50.0 million and $18.9 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 2008, ExxonMobil and Schlumberger accounted for approximately 13 percent and 9 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 $174.4 million at December 31, 2008. The estimated fair value of the Company’s $125.0 million principal amount of Convertible Senior Notes due 2012 was $80.3 million on December 31, 2008. See Note 4.

Stock-Based Compensation — For periods prior to 2006, we accounted for stock-based compensation plans using the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25 “Accounting for Stock Issued to Employees,” and related interpretations. Under these principles no stock-based employee compensation cost related to stock options granted was reflected in net income, as all options granted under the various plans had exercise prices equal to or greater than the fair market value of the underlying common stock on the date of the grants. On January 1, 2006 we adopted the provisions of SFAS No. 123R, “Share-Based Payment” which requires that we include an estimate of the fair value of stock-based compensation costs related to stock options in net income. We elected the modified prospective transition method as permitted by SFAS 123R. Under this transition method, stock-based compensation expense includes (1) compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of December 31, 2005, based on the grant date fair value estimated in accordance with the original pro forma provisions of SFAS 123, “Accounting for Stock-Based Compensation” and (2) compensation expense for all stock-based compensation awards granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. As a result of adopting this standard, we were required to estimate forfeitures, and, if material, record a one-time cumulative effect of a change in accounting principal adjustment. As a result of our estimates, the adoption of this standard did not have a significant effect on our consolidated condensed financial statements and, as such, no adjustment was recorded. Also, in accordance with the modified prospective transition method, our consolidated condensed financial statements for prior periods have not been restated, and do not include the impact of SFAS 123R.

Under SFAS No. 123R, we continue to use 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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 1 —	Summary of Significant Accounting Policies (continued)

each option is estimated on the date of grant. There were no option grants in 2007 or 2008. The following is a summary of valuation assumptions for grants during the year ended December 31, 2006:


		2006

Expected price volatility		16.90%
Risk-free interest rate range		4.23%
Expected life of stock options		3 months

There were no options granted in 2008, 2007 or 2006 under the 1997 Stock Plan. In November 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (“APIC pool”) related to the tax effects of employee stock-based compensation, and to determine the subsequent impact on the APIC pool and consolidated condensed statements of cash flows of the tax effects of employee stock-based compensation awards that are outstanding upon adoption of SFAS No. 123R. We have elected to adopt the transition method described in FSP 123(R)-3. The tax benefit realized for the tax deductions from option exercises and restricted stock vesting totaled $0.3 million for the year ended December 31, 2008 which has been reported as a financing cash inflow in the consolidated condensed statement of cash flows. Cash received from option exercises for the year ended December 31, 2008 was $2.0 million. Refer to Note 9 for additional information about the Company’s stock plans.

Accounting Estimates — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.


Note 2 —	Disposition of Assets

Disposition of Assets — Asset disposition in 2008 included the sale of Rig 206 in Indonesia, for which we recorded no gain or loss and miscellaneous equipment that resulted in a recognized gain of $2.7 million. 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. These two rigs were classified as assets held for sale as of December 31, 2006. In 2006, asset dispositions resulted in a gain of $7.6 million that included the sale of Nigerian Barge Rigs 73 and 75 ($1.8 million), gains on insurance proceeds related to assets damaged ($1.9 million) and other miscellaneous asset sales ($3.9 million).


Note 3 —	Goodwill

As of December 31, 2007, the Company’s goodwill by reporting unit was: U.S. drilling barge rigs — $64.2 million and rental tools — $36.1 million.

At December 31, 2007 and December 31, 2008 goodwill was tested for impairment using SFAS 142. Goodwill was measured at both the U.S. drilling barge rig and rental tools reporting units, by comparing each unit’s carrying value including goodwill to the fair market value estimated for each unit. The fair market value is based on an average weighting of projected discounted future results and the use of comparative market multiples. The use of comparative market multiples (the market approach) compares the Company to other comparable companies based on valuation multiples to arrive at a fair value. At December 31, 2007, no impairment was recorded as the fair market value exceeded the carrying value for both units.

All goodwill was written off at December 31, 2008 primarily as a result of current equity market conditions in which the Company’s market capitalization is significantly under the book value of its assets and due to the uncertainty about financial markets’ return to normalcy. In addition, the U.S. drilling barge market calculation was impacted by current utilization and dayrates in its specific markets and future income

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 3 —	Goodwill (continued)

projections as a result of market conditions and uncertainty discussed above resulted in the impairment of the entire $64.2 million in Goodwill that arose in the acquisition of the segment in 1996. The rental tools impairment was also impacted by discount rates implicit in current market conditions. Accordingly, the entire balance of $36.1 million in goodwill that arose in that reporting unit’s 1996 acquisition was impaired at December 31, 2008.


Note 4 —	Long-Term Debt


	December 31,
	2008		2007
	(Dollars in Thousands)

Convertible Senior Notes payable in July 2012 with interest at 2.125% payable semi-annually in January and July	$	125,000	$	125,000
Senior Notes payable in October 2013 with interest at 9.625% payable semi-annually in April and October net of unamortized premium of $3,073 at December 31, 2008 and $3,721 at December 31, 2007 (effective interest rate of 9.24% at December 31, 2008 and December 31, 2007)		228,073		228,721
Term Note with amortization beginning September 30, 2009 at equal installments of $3.0 million per quarter (effective interest rate of 5.96% at December 31, 2008)		50,000		—
Revolving Credit Facility with interest at prime, plus an applicable margin or LIBOR, plus an applicable margin (interest rate of 5.40% at December 31, 2008)		58,000		20,000

Total debt		461,073		373,721
Less current portion		6,000		20,000

Total long-term debt	$	455,073	$	353,721

The aggregate maturities of long-term debt for the five years ending December 31, 2012 are as follows: $88.0 million for 2009-2011, $145.0 million for 2012 and $225.0 million thereafter.

Activity in 2008 — On May 15, 2008 we 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 the Company’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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 4 —	Long-Term Debt (continued)

of the Revolving Credit Facility (which also reflects 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 executed letter of intent with BP.

Activity in 2007 — On July 5, 2007, we 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 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 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.

	•	*Over-allotment Provision* — The initial offering was for $115 million aggregate principal amount with an over-allotment provision to allow the underwriters an option to purchase an additional $10 million. The option was in fact, exercised for the entire $10 million on the same date on which the notes were issued, and therefore was never outstanding.

	•	*Settlement Feature* — Upon conversion, we will pay shares of our common stock and cash, 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, 2008, none of the conditions allowing holders of the Senior Notes to convert had been met.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 4 —	Long-Term Debt (continued)

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 has been replaced by our 2008 Credit Facility. The 2007 Credit 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 contained customary affirmative and negative covenants such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.

The 2007 Credit Facility was 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 2007 Credit Facility subject to a borrowing base limitation based on 85 percent of eligible receivables plus a value for eligible rental tools equipment. The 2007 Credit Facility calls for a borrowing base calculation only when the 2007 Credit Facility has outstanding loans, including letters of credit, totaling at least $40.0 million. As of December 31, 2007, there were $12.9 million in letters of credit outstanding and $20.0 million of outstanding loans.

On September 27, 2007, we redeemed $100.0 million face value of our Senior Floating Rate Notes pursuant to a redemption notice dated August 17, 2007 at the redemption price of 101.0 percent. A portion of the proceeds from the sale of our 2.125% Convertible Senior Notes were used to fund the redemption. All our Senior Floating Rate Notes have been redeemed

In December 2007 we had a net draw down on our 2007 Credit Facility of $20.0 million which was outstanding as of December 31, 2007, and was reflected in current portion of long-term debt in our December 31, 2007 Consolidated Balance Sheet.

Activity in 2006 — On September 8, 2006, we redeemed $50.0 million face value of our Senior Floating Rate Notes pursuant to a redemption notice dated August 8, 2006 at the redemption price of 102.0 percent.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 4 —	Long-Term Debt (continued)

Proceeds from the sale of our Nigerian barge rigs and cash on hand were used to fund the redemption. An expense of $1.9 million was recognized as loss on extinguishment of debt.

The offerings of the 9.625% Senior Notes and the Senior Floating Rate Notes were effected without registration, in reliance on the registration exemption provided by Section 4(2) of the Securities Act of 1933, as amended, which applies to offers and sales of securities that do not involve a public offering, and Regulation D promulgated under that act. Subsequently, for each of the offerings, the Company filed a registration statement on Form S-4 offering to exchange the new notes for notes of the Company having substantially identical terms in all material respects as the outstanding notes. New notes and exchange notes are governed by the terms of the indentures executed by the Company, the subsidiary guarantors and the trustee. Each of the 9.625% Senior Notes, the Senior Floating Rate Notes and the credit agreement contains customary affirmative and negative covenants, including restrictions on incurrence of debt, sales of assets and dividends. In addition, the credit agreement contains covenants which require minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.


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

Set forth on the following pages are the consolidating condensed financial statements of (i) Parker Drilling, (ii) its restricted subsidiaries that are guarantors of the Senior Notes, Senior Floating Rate Notes and Convertible Senior Notes (“the Notes”) and (iii) 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 to Rule 3-10(a)(1) of Regulation S-X, set forth in sub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100% 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. and Parker Enex, LLC are all non-guarantor subsidiaries. The Company is providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2008 and December 31, 2007 and for the years ended December 31, 2008, 2007 and 2006. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)


	Twelve Months Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

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		(29,257	)		(47,178	)		(308	)		52,210			(24,533	)
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)		5,279			(41,482	)		3,389			8,037			(24,777	)

Income before income taxes		5,073			2,104			19,189			8,037			34,403
Income tax expense (benefit):
Current		(25,850	)		12,432			11,879			—			(1,539	)
Deferred		5,365			4,833			186			—			10,384

Total income tax expense (benefit)		(20,485	)		17,265			12,065			—			8,845

Net income (loss)	$	25,558		$	(15,161	)	$	7,124		$	8,037		$	25,558


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

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)


	Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

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		(29,918	)		(47,183	)		(551	)		52,495			(25,157	)
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)		115,891			(34,687	)		(28,948	)		(101,438	)		(49,182	)

Income (loss) before income taxes		115,725			139,907			(12,393	)		(101,438	)		141,801
Income tax expense (benefit):
Current		(4,237	)		16,217			5,622			—			17,602
Deferred		15,884			2,626			1,611			—			20,121

Income tax expense		11,647			18,843			7,233			—			37,723

Net income (loss)	$	104,078		$	121,064		$	(19,626	)	$	(101,438	)	$	104,078


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

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)


	Twelve Months Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Revenues	$	3		$	510,157		$	123,506		$	(47,231	)	$	586,435
Operating expenses		—			274,862			121,995			(47,231	)		349,626
Depreciation and amortization		—			65,221			4,049			—			69,270

Operating gross margin		3			170,074			(2,538	)		—			167,539

General and administration expense(1)		(166	)		(31,606	)		(14	)		—			(31,786	)
Gain (loss) on disposition of assets, net		(6	)		7,416			163			—			7,573

Total operating income (loss)		(169	)		145,884			(2,389	)		—			143,326

Other income and (expense):
Interest expense		(36,313	)		(47,178	)		(1,674	)		53,567			(31,598	)
Changes in fair value of derivative positions		40			—			—			—			40
Interest income		50,102			8,458			2,970			(53,567	)		7,963
Loss on extinguishment of debt		(1,912	)		—			—			—			(1,912	)
Minority interest		—			—			(229	)		—			(229	)
Other		21			(216	)		40			—			(155	)
Equity in net earnings of subsidiaries		80,335			—			—			(80,335	)		—

Total other income and (expense)		92,273			(38,936	)		1,107			(80,335	)		(25,891	)

Income (loss) before income taxes		92,104			106,948			(1,282	)		(80,335	)		117,435
Income tax expense (benefit):
Current		(4,873	)		21,243			4,284			—			20,654
Deferred		15,951			(4,144	)		3,948			—			15,755

Income tax expense		11,078			17,099			8,232			—			36,409

Net income (loss)	$	81,026		$	89,849		$	(9,514	)	$	(80,335	)	$	81,026


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

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)


	December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

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
Goodwill		—			—			—			—			—
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		35,518			21,215			8,059			—			64,792

Total assets	$	1,160,469		$	1,771,151		$	341,503		$	(2,059,492	)	$	1,213,631


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		455,073			—			—			—			455,073
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 (Note 13)		—			—			—			—			—
Stockholders’ equity:
Common stock		18,910			39,899			21,153			(61,052	)		18,910
Capital in excess of par value		603,731			1,045,727			141,112			(1,186,839	)		603,731
Retained earnings (accumulated deficit)		(52,237	)		(255,415	)		(13,123	)		268,538			(52,237	)

Total stockholders’ equity		570,404			830,211			149,142			(979,353	)		570,404

Total liabilities and stockholders’ equity	$	1,160,469		$	1,771,151		$	341,503		$	(2,059,492	)	$	1,213,631

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)


	December 31, 2007
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

ASSETS
Current assets:
Cash and cash equivalents	$	31,326		$	8,314		$	20,484		$	—		$	60,124
Marketable securities		—			—			—			—			—
Accounts and notes receivable, net		79,688			187,663			80,139			(180,784	)		166,706
Rig materials and supplies		—			10,667			13,597			—			24,264
Deferred costs		—			1,553			6,242			—			7,795
Deferred income taxes		9,423			—			—			—			9,423
Other tax assets		59,673			(23,395	)		(3,746	)		—			32,532
Other current assets		174			10,578			11,587			—			22,339

Total current assets		180,284			195,380			128,303			(180,784	)		323,183

Property, plant and equipment, net		79			423,652			162,035			122			585,888
Goodwill		—			100,315			—			—			100,315
Investment in subsidiaries and intercompany advances		813,248			963,269			(58,320	)		(1,718,197	)		—
Investment in and advances to unconsolidated joint venture		—			267			(4,620	)		—			(4,353	)
Other noncurrent assets		40,113			20,805			11,036			—			71,954

Total assets	$	1,033,724		$	1,703,688		$	238,434		$	(1,898,859	)	$	1,076,987


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current debt	$	20,000		$	—		$	—		$	—		$	20,000
Accounts payable and accrued liabilities		48,820			221,363			64,577			(247,408	)		87,352
Accrued income taxes		1,765			10,790			4,273			—			16,828

Total current liabilities		70,585			232,153			68,850			(247,408	)		124,180

Long-term debt		353,721			—			—			—			353,721
Other long-term liabilities		110			48,174			8,034			—			56,318
Long-term deferred tax liability		1			1,237			6,806			—			8,044
Intercompany payables		74,583			576,746			38,074			(689,403	)		—
Commitments and contingencies (Note 13)		—			—			—			—			—
Stockholders’ equity:
Common stock		18,653			39,900			21,152			(61,052	)		18,653
Capital in excess of par value		593,866			1,045,732			115,765			(1,161,497	)		593,866
Retained earnings (accumulated deficit)		(77,795	)		(240,254	)		(20,247	)		260,501			(77,795	)

Total stockholders’ equity		534,724			845,378			116,670			(962,048	)		534,724

Total liabilities and stockholders’ equity	$	1,033,724		$	1,703,688		$	238,434		$	(1,898,859	)	$	1,076,987

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)


	Twelve Months Ending December 31, 2008
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Cash flows from operating activities:
Net income (loss)	$	25,558		$	(15,161	)	$	7,124		$	8,037		$	25,558
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		5,365			4,833			186			—			10,384
Equity in loss of unconsolidated joint venture		—			1,105			—			—			1,105
Expenses not requiring cash		9,363			—			—			—			9,363
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

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)


	Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Cash flows from operating activities:
Net income (loss)	$	104,078		$	121,064		$	(19,626	)	$	(101,438	)	$	104,078
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		15,884			2,626			1,611			—			20,121
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		11,187			(590	)		—			—			10,597
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 unconsolidated 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 (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

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)


	Year Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Cash flows from operating activities:
Net income (loss)	$	81,026		$	89,849		$	(9,514	)	$	(80,335	)	$	81,026
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		—			65,221			4,049			—			69,270
Amortization of debt issuance and premium		764			—			—			—			764
Loss on extinguishment of debt		910			—			—			—			910
Gain (loss) on disposition of assets		6			(7,416	)		(163	)		—			(7,573	)
Deferred tax expense (benefit)		15,951			(4,144	)		3,948			—			15,755
Expenses not requiring cash		8,474			1,200			—			—			9,674
Equity in net earnings of subsidiaries		(80,335	)		—			—			80,335			—
Change in operating assets and liabilities		(2,952	)		6,797			(6,803	)		—			(2,958	)

Net cash provided by (used in) operating activities		23,844			151,507			(8,483	)		—			166,868

Cash flows from investing activities:
Capital expenditures		—			(191,308	)		(3,714	)		—			(195,022	)
Investment in unconsolidated joint venture		(10,000	)		—			—			—			(10,000	)
Proceeds from the sale of assets		(6	)		48,481			2,315			—			50,790
Proceeds from insurance claims		—			4,501			—			—			4,501
Purchase of marketable securities		(196,120	)		(2,000	)		—			—			(198,120	)
Sale of marketable securities		151,200			2,000			—			—			153,200

Net cash used in investing activities		(54,926	)		(138,326	)		(1,399	)		—			(194,651	)

Cash flows from financing activities:
Principal payments under debt obligations		(50,000	)		—			—			—			(50,000	)
Proceeds from common stock offering		99,947			—			—			—			99,947
Proceeds from stock options exercised		7,537			—			—			—			7,537
Excess tax benefit from stock options exercised		2,326			—			—			—			2,326
Intercompany advances, net		(677	)		(9,959	)		10,636			—			—

Net cash provided by (used in) financing activities		59,133			(9,959	)		10,636			—			59,810

Net increase in cash and cash equivalents		28,051			3,222			754			—			32,027
Cash and cash equivalents at beginning of year		31,978			11,145			17,053			—			60,176

Cash and cash equivalents at end of year	$	60,029		$	14,367		$	17,807		$	—		$	92,203

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 6 —	Derivative Financial Instruments

The Company entered into two variable-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% for a three-year period beginning September 1, 2006 and terminating September 2, 2008 and fixed the interest rate on an additional $50.0 million at 8.48% for the two-year period beginning September 1, 2006 and terminating September 4, 2007. 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 second agreement, signed on September 14, 2004, fixed the interest rate on $150.0 million at 6.54% for the three-month period beginning December 1, 2004 and terminating March 1, 2005. Options to extend $100.0 million at a fixed interest rate of 7.08% for a six-month period beginning March 1, 2005 and to extend $50.0 million at a fixed interest rate of 7.60% for an 18-month period beginning March 1, 2005 and terminating September 1, 2006, were given to the issuer, Bank of America, N.A. In the first quarter of 2005, Bank of America, N.A. allowed these options to expire unexercised.

The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-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 and for the year ended December 31, 2006 we recognized a minimal change in the fair value of the derivative positions. On July 17, 2007, we 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,
	2008			2007		2006
	(Dollars in Thousands)

United States	$	(25,480	)	$	127,483	$	99,024
Foreign		59,883			14,318		18,411

	$	34,403		$	141,801	$	117,435

Income tax expense (benefit) is summarized as follows:


	Year Ended December 31,
	2008			2007			2006
	(Dollars in Thousands)

Current:
United States:
Federal	$	(3,751	)	$	13,860		$	13,046
State		407			791			—
Foreign		1,805			2,951			7,608
Deferred:
United States:
Federal		10,571			16,559			30,436
State		(538	)		4,290			(12,617	)
Foreign		351			(728	)		(2,064	)

	$	8,845		$	37,723		$	36,409

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,
	2008						2007						2006
				% of Pre-Tax						% of Pre-Tax						% of Pre-Tax
	Amount			Income			Amount			Income			Amount			Income

Computed Expected Tax Expense	$	12,041			35	%	$	49,630			35	%	$	41,104			35	%
Foreign Taxes		22,391			65	%		12,669			9	%		5,820			5	%
State Taxes, net of federal benefit		66			—			5,080			4	%		—			—
Foreign Tax Credits		(20,404	)		(59	)%		(16,020	)		(11	)%		—			—
Kazakhstan Tax Credits		—			—			(22,547	)		(16	)%		—			—
Kazakhstan FIN 48 Items		(13,002	)		(38	)%		(12,427	)		(9	)%		—			—
Change in Valuation Allowance		(1,835	)		(5	)%		5,764			4	%		—			—
Foreign Corporation Income		2,997			9	%		8,916			6	%		1,524			2	%
Adoption of FIN 48		—			—			7,807			5	%		—			—
State NOL		—			—			—			—			(12,617	)		(11	)%
Tax Benefit of Foreign Divestment		(3,456	)		(10	)%		—			—			—			—
Other Permanent Differences, Net		(1,260	)		(4	)%		(161	)		—			1,404			1	%
Other		(1,329	)		(4	)%		(988	)		—			(826	)		(1	)%
Goodwill		12,636			37	%		—			—			—			—

Actual Tax Expense	$	8,845			26	%	$	37,723			27	%	$	36,409			31	%

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

The components of the Company’s deferred tax assets and (liabilities) as of December 31, 2008 and 2007 are shown below:


	December 31,
	2008			2007
	(Dollars in Thousands)

Deferred tax assets
Current deferred tax assets:
Reserves established against realization of certain assets	$	5,362		$	6,563
Accruals not currently deductible for tax purposes		4,373			2,860

Gross current deferred tax assets		9,735			9,423
Current deferred tax valuation allowance		—			—

Net current deferred tax assets		9,735			9,423

Non-current deferred tax assets:
State net operating loss carryforwards		4,273			9,217
Other state deferred tax asset		5,015			—
Foreign tax credits		—			6,300
Other long term liabilities		2,149			2,149
Deferred compensation		809			370
Note hedge interest		9,304			11,239
Percentage of completion construction projects		491			—
Goodwill		5,810			—
FIN 48		5,162			13,381
Property, plant and equipment		2,941			—
Other		(531	)		—

Gross long-term deferred tax assets		35,423			42,656
Valuation Allowance		(4,556	)		(6,391	)

Net non-current deferred tax assets		30,867			36,265

Net deferred tax assets		40,602			45,688

Deferred tax liabilities:
Non-current deferred tax liabilities:
Property, plant and equipment		(4,507	)		8,571
Goodwill		—			(14,336	)
Deferred tax impact of 481 (a) adjustment related to FTCs		(4,645	)		—
Foreign tax local		(342	)		—
Federal benefit of foreign tax		(1,032	)		—
Other		2,296			1,577

Net non-current deferred tax liabilities		(8,230	)		(4,188	)

Net deferred tax asset	$	32,372		$	41,500

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 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 the Company’s ability to recognize the benefit for the foreign tax credits. In addition, in 2008, we recognized a $12.2 million benefit related to our ability to claim foreign tax credits from prior years due to a change from deductions to credits. A valuation allowance of $4.1 million was established related to a Papua New Guinea deferred tax asset based on management’s analysis that it was not “more likely than not” the Company could realize the benefit in future periods. At December 31, 2008, the Company had $85.3 million of gross state NOL carryforwards. For tax purposes, the state NOL carryforwards expire over a 15 year period ending December 31, 2014 through 2023.

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.

The 2006 results reflect the reversal of valuation allowances related to NOL carryforwards and other deferred tax assets in the U.S. The valuation allowances were originally recorded in accordance with GAAP as an offset to the Company’s deferred tax assets, which consisted primarily of federal and state NOL carryforwards. GAAP required the Company to record a valuation allowance unless it was “more likely than not” that the Company could realize the benefit of the NOL carryforwards and deferred tax assets in future periods. Having returned to profitability in 2005, the Company determined that earnings performance should allow the Company to benefit from the federal NOL carryforwards and that the valuation allowance for federal NOLs was no longer required

Effective January 1, 2007, the company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	In Millions

Balance at January 1, 2008		(13.1	)
Decreases related to prior year tax positions		4.6
Increases related to current year tax positions		(3.3	)
Lapse of statute		0.1

Balance at December 31, 2008		(11.7	)

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, 2008:


United States — Federal		1985-present
Bolivia		2001-present
Kazakhstan		2003-present
Mexico		2003-present
Papua New Guinea		2002-present
Russia		2006-present
New Zealand		2003-present
Colombia		2006-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, 2008, the company had a liability for unrecognized tax benefits of $11.7 million (all of which, if recognized, would favorably affect the company’s effective tax rate).

We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2007 and December 31, 2008 we had approximately $40.3 million and $8.4 million of accrued interest and penalties related to uncertain tax positions, respectively. The Company recognized a reduction of $32.7 million of interest and an increase of $0.8 million of penalties on unrecognized tax benefits for the year ended December 31, 2008.


Note 8 —	Saudi Arabia Joint Venture

On April 9, 2008, a subsidiary of Parker 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’s subsidiary as consideration for the 50 percent share interest of the Parker subsidiary and partial repayment of investments and advances of the Parker subsidiary to ARPD, including a $5.0 million advance in January 2008. During the first quarter of 2008, the Parker subsidiary made the decision to terminate any future funding to ARPD, and accordingly, the Company did not record equity in losses of ARPD in the first quarter of 2008. We recognized a $1.1 million loss, net of income taxes, in the first quarter of 2008 primarily as a result of nonrecoverable costs, as per the terms of the Sale Agreement, incurred by the Parker affiliate to support ARPD operations during the first quarter of 2008. The Parker 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 obligates the resulting Saudi shareholders to indemnify the Parker 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. Each party has agreed to waive any claims that it may have against the other party arising out of the business of ARPD on or before the closing date, and subject to the formal transfer of the shares the Parker subsidiary has agreed to disclaim any remaining rights with respect to the unpaid portion of shareholder loans and payables owed by ARPD to the Parker subsidiary. The formal transfer of shares was approved by the Saudi Arabian authorities in July 2008.

Parker Drilling’s subsidiary incurred $9.8 million in losses related to rig operations attributable to its 50 percent interest in ARPD in 2007. These losses are primarily a result of cost overruns due to increases in vendor costs, construction costs to remedy defects in rigs and components, equipment rentals incurred in order to commence operation until equipment purchases were received and additional interest expense and depreciation expense related to significant unanticipated rig construction costs. Our subsidiary had also

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 8 —	Saudi Arabia Joint Venture (continued)

reserved $3.5 million related to certain advances made to ARPD since the inception of the contract; these reserves are not reflected on ARPD financial statements shown below.

Al Rushaid-Parker Drilling, LLC

Condensed Statement of Operations
(Dollars in Thousands)
(Unaudited)


	Year Ended
	December 31,
	2007

Drilling revenues	$	12,287

Drilling operating expenses		28,406
Other expenses		31,042

Total expenses		59,448

Net loss	$	(47,161	)

Al Rushaid-Parker Drilling, LLC

Condensed Balance Sheet
(Dollars in Thousands)
(Unaudited)


	December 31,
	2007

ASSETS
Total current assets	$	32,544
Net property, plant and equipment		185,383

Total assets	$	217,927

LIABILITIES AND STOCKHOLDERS’ EQUITY
Total current debt	$	8,785
Total other current liabilities		74,766
Long-term debt — third party		151,467
Long-term debt — related party		29,536
Total stockholders’ equity		(46,627	)

Total liabilities and stockholders’ equity	$	217,927


Note 9 —	Common Stock and Stockholders’ Equity

Common Stock Offering — On January 23, 2006, we completed the public offering of 8,900,000 shares of our common stock at a price of $11.23 per share, or a total of $99.9 million of net proceeds before expenses, but after underwriting discount.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 9 —	Common Stock and Stockholders’ Equity (continued)

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

The 1991 Stock Grant Plan (“1991 Grant Plan”) authorized 3,160,000 shares of common stock to be issued to officers, key employees and non-employee directors of the Company and its affiliates who are responsible for and contribute to the management, growth and profitability of the business of the Company. The 1991 Grant Plan was frozen as of April 27, 2005, the date on which the 2005 Plan (as defined below) was approved by shareholders. As of such date, there were 1,462,195 shares available for granting under the 1991 Grant Plan, which are now available for granting under the 2005 Plan. Any awards that are forfeited or expire and would have been available for re-issuance under the 1991 Grant Plan are available for issuance under the 2005 Plan referenced below.

The 1994 Non-Employee Director Stock Incentive Plan (“1994 Director Plan”) provided for the issuance of options to purchase up to 200,000 shares of Parker Drilling’s common stock. The option price per share is equal to the fair market value of a Parker Drilling share on the date of grant. The term of each option was 10 years, and an option first becomes exercisable six months after the date of grant. The 1994 Director Plan was frozen as of April 27, 2005, the date on which the 2005 Plan (as defined below) was approved by shareholders. As of such date there were 15,000 shares available for issuance under this plan which are now available for granting under the 2005 Plan. Any awards that are forfeited or expire and would have been available for re-issuance under the 1994 Director Plan are available for issuance under the 2005 Plan referenced below.

The 1994 Executive Stock Option Plan (“1994 Executive Option Plan”) provided that the directors may grant a maximum of 2,400,000 shares to key employees of the Company and its subsidiaries through the granting of stock options, stock appreciation rights and restricted and deferred stock awards. The option price per share could not be less than 50 percent of the fair market value of a share on the date the option is granted, and the maximum term of a non-qualified option could not exceed 15 years and the maximum term of an incentive option was 10 years. The 1994 Executive Option Plan was frozen as of April 27, 2005, the date on which the 2005 Plan (as defined below) was approved by shareholders. As of such date there were 1,037,000 shares available for granting, which are now available for granting under the 2005 Plan. Any awards that are forfeited or expire and would have been available for re-issuance under the 1994 Executive Option Plan are available for issuance under the 2005 Plan referenced below.

The Amended and Restated 1997 Stock Plan (“1997 Plan”) authorized 8,800,000 shares to be available for granting to officers and key employees who, in the opinion of the board of directors, were in a position to contribute to the growth, management and success of the Company. This plan was approved by the board of directors as a “broad-based” plan under the interim rules of the New York Stock Exchange and, as a result, more than 50 percent of the awards under this plan have been made to non-executive employees. The option price per share could not be less than the fair market value on the date the option was granted for incentive options and not less than par value of a share of common stock for non-qualified options. The maximum term of an incentive option was 10 years and the maximum term of a non-qualified option was 15 years. The 1997 Plan was frozen as of April 27, 2005, the date on which the 2005 Plan (as defined below) was approved by shareholders. As of such date, the 1,435,939 shares available for granting are now available for granting under the 2005 Plan. Any awards that are forfeited or expire and would have been available for re-issuance under the 1997 Plan are available for issuance under the 2005 Plan referenced below.

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. As of the date of approval of the 2005 Plan on April 27, 2005, the 1991 Grant Plan, the 1994 Director Plan, the 1994 Executive Option Plan and the 1997 Plan (the “Frozen Plans”) were frozen and the 3,950,134 shares that were available for granting immediately prior to the freezing

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 9 —	Common Stock and Stockholders’ Equity (continued)

of the Frozen Plans are now available for granting under the terms of the 2005 Plan. In 2005, the Company de-listed the shares of common stock that were listed and unissued under the Frozen Plans and filed a separate listing application with the New York Stock Exchange, listing the 3,950,134 shares under the 2005 Plan. The 3,950,134 shares have also been registered under a Form S-8 filed with the Securities and Exchange Commission (“SEC”) on May 6, 2005.

The Company issued 755,000 restricted shares in 2003 to selected key personnel, of which 37,500 shares reverted back to the Company. In March 2004, 377,500 shares vested after the closing stock price of $3.50 per share was met for 30 consecutive days resulting in $1.0 million of expense. In March 2005, the remaining 340,000 shares vested after the closing stock price of $5.00 per share was met for 30 consecutive days resulting in $0.7 million of expense. In 2005, the Company issued 1,027,500 restricted shares to the board of directors and selected key personnel, of which 22,500 shares reverted back to the Company. The amortization expense in 2005 for the restricted shares issued in 2005 was $1.9 million. In 2006, the Company issued 753,500 restricted shares to selected key personnel. The amortization expense in 2006 for all issued and outstanding restricted shares was $6.5 million.

In 2007, the Company issued 922,845 restricted shares to selected key personnel. Incentive grants to senior management members included in this issuance were based on the attainment of specific goals. The amortization expense in 2007 for 2007 awards and previously awarded outstanding restricted shares was $8.5 million.

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 on the attainment of pre-established performance goals. The amortization expense in 2008 for 2008 awards and previously awarded outstanding restricted shares was $7.0 million.

In 2008 the Company obtained approval from Shareholders to increase the total number of common shares available for future awards under the Plan by 2,000,000 shares. This amendment to the 2005 Plan was approved by Shareholders at the Company’s Annual Meeting on April 24, 2008.

Information regarding the Company’s stock option plans is summarized below:


	1994 Non-Employee
	Director Stock Incentive Plan
				Weighted
				Average
				Exercise		Intrinsic
	Shares			Price		Value

Outstanding at December 31, 2007		14,000		$	9.573
Granted		—			—
Exercised		(4,000	)		3.280	$	23,191
Cancelled		(10,000	)		12.090

Outstanding at December 31, 2008		—			—

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 9 —	Common Stock and Stockholders’ Equity (continued)


	1997 Stock Plan
	Incentive Options					Non-Qualified Options
				Weighted					Weighted
				Average					Average
				Exercise					Exercise		Intrinsic
	Shares			Price		Shares			Price		Value

Outstanding at December 31, 2007		46,240		$	10.813		921,560		$	3.770
Granted		—			—		—			—
Exercised		—			—		(507,500	)		3.855	$	2,231,580
Cancelled		(46,240	)		10.813		(123,760	)		5.516

Outstanding at December 31, 2008		—		$	—		290,300		$	2.877

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

$1.960-$4.200

290,300

1.40 years

2.877

6,677

Exercisable Options

Weighted

Average

Aggregate

Number of

Exercise

Intrinsic

Plan

Exercise Prices

Shares

Price

Value

1997 Stock Plan

Non-qualified

$1.960-$4.200

290,300

2.877

6,677

The Company had 1,457,862 and 1,143,360 shares held in Treasury stock at December 31, 2008 and 2007, respectively.

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


	December 31,
	2008		2007

Stock plans		2,091,037		1,426,589
Stock bonus plan		355,359		304,402

Total shares reserved for issuance		2,446,396		1,730,991

Stockholder Rights Plan — The Company adopted a stockholder rights plan on June 25, 1998, to assure that the Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all stockholders a fair price. The rights plan was not adopted in response to any

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 9 —	Common Stock and Stockholders’ Equity (continued)

specific takeover proposal. Under the rights plan, the Company’s board of directors declared a dividend of one right to purchase one one-thousandth of a share of a new series of junior participating preferred stock for each outstanding share of common stock. The plan was amended on September 22, 1998, to eliminate the restriction on the board of directors’ ability to redeem the shares for two years in the event the majority of the board of directors does not consist of the same directors that were in office as of June 25, 1998 (“Continuing Directors”), or directors that were recommended to succeed Continuing Directors by a majority of the Continuing Directors.

The rights may only be exercised 10 days following a public announcement that a third party has acquired 15 percent or more of the outstanding common shares of the Company or 10 days following the commencement of, or announcement of, an intention to make a tender offer or exchange offer, the consummation of which would result in the beneficial ownership by a third party of 15 percent or more of the common shares. When exercisable, each right will entitle the holder to purchase one one-thousandth share of the new series of junior participating preferred stock at an exercise price of $30, subject to adjustment. If a person or group acquires 15 percent or more of the outstanding common shares of the Company, each right, in the absence of timely redemption of the rights by the Company, will entitle the holder, other than the acquiring party, to purchase for $30, common shares of the Company having a market value of twice that amount.

The stockholder rights plan expired by its own terms on June 30, 2008.


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, 2008
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic EPS:
Income from continuing operations	$	25,558,000		111,400,396	$	0.23
Discontinued operations		—				—

Net income	$	25,558,000			$	0.23

Effect of dilutive securities:
Stock options and restricted stock				1,030,149	$	—
Diluted EPS:
Income from continuing operations	$	25,558,000		112,430,545	$	0.23
Discontinued operations		—				—

Net income	$	25,558,000			$	0.23

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) (continued)


	For The Year Ended December 31, 2007
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic EPS:
Income from continuing operations	$	104,078,000		109,542,364	$	0.95
Discontinued operations		—				—

Net income	$	104,078,000			$	0.95

Effect of dilutive securities:
Stock options and restricted stock				1,314,330	$	(0.01	)
Diluted EPS:
Income from continuing operations	$	104,078,000		110,856,694	$	0.94
Discontinued operations		—				—

Net income	$	104,078,000			$	0.94


	For The Year Ended December 31, 2006
	Income (Loss)		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic EPS:
Loss from continuing operations	$	81,026,000		106,552,015	$	0.76
Discontinued operations		—				—

Net loss	$	81,026,000			$	0.76

Effect of dilutive securities:
Stock options and restricted stock				1,586,368	$	(0.01	)
Diluted EPS:
Loss from continuing operations	$	81,026,000		108,138,383	$	0.75
Discontinued operations		—				—

Net loss	$	81,026,000			$	0.75

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, 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. Options to purchase 2,135,166 shares of common stock with exercise prices ranging from $8.875 to $12.188 per share were outstanding during the year ended December 31, 2006, 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 and are made in Parker Drilling common stock, but to encourage diversity of investment, Parker Drilling common stock is not an investment option for voluntary contributions. The Company issued 443,231,

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 11 —	Employee Benefit Plan (continued)

283,581 and 219,204 shares to the Plan in 2008, 2007 and 2006, respectively, with the Company recognizing expense of $2.8 million, $2.5 million and $1.8 million for each of the respective periods.


Note 12 —	Business Segments

Through the year ended December 31, 2007, the Company was organized into three primary business segments: U.S. drilling operations, international drilling operations and rental tools. In the first quarter of 2008, the Company created a new 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 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. The Company anticipates further growth of this segment of our business and reviews and assesses its performance separately. Financial information for reportable segments for 2007 has been recasted below to reflect this change. In the second quarter of 2008, the Company created a new segment called Construction contracts to reflect the Company’s Engineering, Procurement, Construction and Installation contract (“EPCI”). The construction contract segment income (fees) is accounted for on a percentage of completion basis using the cost-to-cost method. Revenues received and costs incurred related to the contract are recorded on a gross basis.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 12 —	Business Segments (continued)


	Year Ended December 31,
Operations by Industry Segment	2008			2007			2006
	(Dollars in Thousands)

Revenues:
U.S. drilling(1)	$	173,633		$	225,263		$	191,225
International drilling(1)		325,096			213,566			184,280
Project management and engineering services(1)		110,147			77,713			88,936
Construction contract(1)		49,412			—			—
Rental tools(1)		171,554			138,031			121,994

Total revenues		829,842			654,573			586,435

Operating income:
U.S. drilling(2)		53,964			97,679			83,296
International drilling(2)		41,786			31,046			13,923
Project management and engineering services(2)		18,470			12,732			13,616
Construction contract(2)		2,597			—			—
Rental tools(2)		74,689			59,264			56,704

Total operating income		191,506			200,721			167,539
General and administrative expense		(34,708	)		(24,708	)		(31,786	)
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			7,573

Total operating income		59,180			190,983			143,326
Interest expense		(24,533	)		(25,157	)		(31,598	)
Changes in fair value of derivative positions		—			(671	)		40
Loss on extinguishment of debt		1,405			(2,396	)		(1,912	)
Equity in loss of unconsolidated joint venture, net of taxes		—			(27,101	)		—
Minority interest		(1,105	)		(1,000	)		(229	)
Other		(544	)		7,143			7,808

Income from continuing operations before income taxes	$	34,403		$	141,801		$	117,435

Identifiable assets:
U.S. drilling	$	157,508		$	235,030
International drilling		540,574			441,282
Rental tools		125,170			177,033

Total identifiable assets		823,252			853,345
Corporate assets		390,379			223,642

Total assets	$	1,213,631		$	1,076,987


(1)		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. In 2006, ExxonMobil accounted for approximately 14 percent of the Company’s total revenues. ExxonMobil accounted for approximately $65.8 million of the Company’s project management and engineering services segment revenues and approximately $19.0 million of the Company’s rental tools segment revenues.

(2)		Operating income — revenues less direct operating expenses, including depreciation and amortization expense.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 12 —	Business Segments (continued)


	Year Ended December 31,
Operations by Geographic Area	2008			2007			2006
	(Dollars in Thousands)

Revenues:
United States	$	399,962		$	369,170		$	309,757
Latin America		122,521			75,683			31,466
Asia Pacific		56,998			67,037			79,665
Africa and Middle East		40,036			14,580			24,219
CIS		210,325			128,103			141,328

Total revenues		829,842			654,573			586,435

Operating income:
United States(1)		132,991			158,778			136,690
Latin America(1)		27,072			26,825			(5,679	)
Asia Pacific(1)		7,668			10,670			19,884
Africa and Middle East(1)		(13,293	)		(14,466	)		(2,594	)
CIS(1)		37,068			18,914			19,238

Total operating income		191,506			200,721			167,539

General and administrative expense		(34,708	)		(24,708	)		(31,786	)
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			7,573
Total operating income		59,180			190,983			143,326
Interest expense		(24,533	)		(25,157	)		(31,598	)
Changes in fair value of derivative positions		—			(671	)		40
Loss on extinguishment of debt		—			(2,396	)		(1,912	)
Equity in loss of unconsolidated joint venture, net of taxes		(1,105	)		(27,101	)		—
Minority interest		—			(1,000	)		(229	)
Other		861			7,143			7,808

Income from continuing operations before income taxes	$	34,403		$	141,801		$	117,435

Long-lived assets:(2)
United States	$	396,992		$	447,235
Latin America		63,560			54,415
Asia Pacific		27,663			29,200
Africa and Middle East		40,724			59,067
CIS		146,609			96,286

Total long-lived assets	$	675,548		$	686,203


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

(2)		Is primarily comprised of property, plant and equipment, net and goodwill and excludes assets held for sale.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 13 —	Commitments and Contingencies

At December 31, 2008, the Company had an $80.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2008, $12.8 million of availability has been reserved to support letters of credit that have been issued and $58.0 million of loans outstanding under the facility.

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, 2008, under operating leases with non-cancelable terms are as follows (dollars in thousands):


2009	$	4,689
2010		1,739
2011		1,125
2012		831
2013		262

Total	$	8,646

Total rent expense for all operating leases amounted to $13.7 million for 2008, $10.1 million for 2007 and $9.0 million for 2006.

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. This coverage may not adequately protect the Company against liability from all potential consequences.

As of December 31, 2008, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $8.1 million and the related insurance recoveries/receivables were $2.5 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 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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 13 —	Commitments and Contingencies (continued)

of the Company, but there can be no assurance that an adverse ruling not anticipated by the Company will not have a material adverse effect on the results of operations or the financial position of the Company.

Kazakhstan Tax Claims

On October 12, 2005, 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”) assessing PKD Kazakhstan an amount of KZT (Kazakhstan Tenge) 14.9 billion (approximately $125.8 million). Approximately KZT7.5 billion or $63.3 million was assessed for import Value Added Tax (“VAT”), administrative fines and interest on equipment imported to perform the drilling contracts (the “VAT Assessment”) and approximately KZT7.4 billion or $62.5 million for corporate income tax, individual income tax and social tax, administrative fines and interest in connection with the reimbursements received by PDCIL from a client for the upgrade of Barge Rig 257 and other issues related to PKD Kazakhstan’s operations in the Republic of Kazakhstan (the “Income Tax Assessment”).

On May 24, 2006, the Supreme Court of the Republic of Kazakhstan (“SCK”) issued a decision upholding the VAT Assessment. Consistent with its contractual obligations, on November 20, 2006, the client advanced the actual amount of the VAT Assessment and this amount has been remitted to MinFin. The administrative fines related to the VAT Assessment are being appealed by the client who is contractually responsible to reimburse PKD Kazakhstan for any administrative fines ultimately assessed. The client has also contractually agreed to reimburse PKD Kazakhstan for any incremental income taxes that PKD Kazakhstan incurs from the reimbursement of this VAT Assessment.

After multiple appeals to the SCK and two meetings of the U.S. Competent Authorities under the Mutual Agreement Procedure of the U.S.- Kazakhstan Tax Treaty, the SCK ultimately upheld the Income Tax Assessment and on December 12, 2007, PKD Kazakhstan paid the principal tax portion of the Income Tax Assessment, net of estimated taxes previously paid. After a further appeal against the interest portion of the notice of assessment, on February 25, 2008, the Atyrau Economic Court issued a ruling that interest on the income tax assessed should accrue from the October 12, 2005 assessment date as opposed to the original assessment in 2001, which resulted in a revised interest assessment by the Atyrau Tax Committee of approximately US$13 million, which was paid by PKD Kazakhstan on March 14, 2008, in final resolution of this matter. Income tax for the year ended December 31, 2008 includes a benefit of $13.4 million of FIN 48 interest and foreign currency exchange rate fluctuations related to this final resolution.

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 court dismissed the case on the basis that Houston, Texas, is not the appropriate location for this suit to be filed. The plaintiffs have appealed this dismissal; however, the Company believes the plaintiffs’ prospects of being successful on appeal are remote. No amounts were accrued at December 31, 2008.

Asbestos-Related Claims

In August 2004, the Company 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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 13 —	Commitments and Contingencies (continued)

affiliated with the Company, including companies that allegedly manufactured drilling- related products containing asbestos that are the subject of the complaints.

The complaints allege that the Company’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 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 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, 2008.

Gulfco Site

Several years ago 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 in 2003 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 successor to a party who owned the Gulfco site during the time when chemical releases took place there. Two other parties have been performing that 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. The subsidiary is continuing to evaluate its relationship to the site and has conferred with the EPA and the other parties in an effort to resolve the matter. The Company has not yet estimated the amount or impact on our operations, financial position or cash flows of any costs related to the site. To date, the EPA and the other two parties have spent over $2.7 million studying and conducting initial remediation of the site. It is anticipated that 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. Although we can provide no assurance as to the total amount necessary to finally resolve this matter, we currently anticipate that the total claim will not exceed $5 million and will be shared by all responsible parties. The Company does not believe it has any obligation with respect to the remediation of the property, and accordingly no accrual was made as of December 31, 2008.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 13 —	Commitments and Contingencies (continued)

Customs Agent Investigation

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. In response to those requests, the Company is conducting an internal investigation. The DOJ and the SEC are conducting parallel investigations into possible violations of U.S. law by the Company, including the Foreign Corrupt Practices Act (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. 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. If we are not in compliance with the FCPA and other laws governing the conduct of business with foreign government entities (including other United States laws and regulations as well as local laws), we may be subject to criminal and civil penalties and other remedial measures, which could have an adverse impact on our business, results of operations, financial condition and liquidity.

Economic Sanctions Compliance

Our international operations 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 that may have violated applicable U.S. laws and regulations. In addition, we have engaged in drilling wells in the Korpedje Field in Turkmenistan, from where natural gas may be exported by pipeline to Iran. We are currently reviewing 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. Although we are unable to predict the scope or result of this internal review or its ultimate outcome, we have initiated voluntary disclosure of these potential compliance issues to the appropriate U.S. government agency. If we are 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.


Note 14 —	Related Party Transactions

Consulting Agreement

In connection with the retirement of Robert L. Parker Sr. as Chairman of the Board of Directors of the Company, effective April 28, 2006, the Company entered into a Consulting Agreement with Mr. Parker Sr. on April 4, 2006 (the “Consulting Agreement”). The Consulting Agreement has a term of two years, and provides for


	(i)	A consulting contract and severance agreement,


	(ii)	Payment of unpaid vacation pay that has accrued through April 30, 2006,

	(iii)	A lump sum payment of $397,500 on November 2, 2006,

	(iv)	Monthly payments of $37,500 and $28,750 commencing on May 1, 2006, for two years related to the severance agreement and the consulting agreement, respectively, and

	(v)	Medical coverage under the Company’s medical plan for Mr. Parker Sr. and his spouse through April 30, 2008.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 14 —	Related Party Transactions (continued)

If Mr. Parker Sr. should die before the end of the term, the payments shall continue to be made to his spouse, if she survives him, and if she does not survive him, to Mr. Parker’s estate.

The Consulting Agreement requires Mr. Parker Sr. to provide certain services to the Company during the term of the Consulting Agreement, including without limitation, assisting with projects on which Mr. Parker Sr. worked while Chairman of the Company, bridging relationships with customers, and assisting with marketing efforts utilizing relationships developed during Mr. Parker Sr.’s tenure with the Company.

During the term of the Consulting Agreement, Mr. Parker Sr. will maintain the confidentiality of any information he obtains while an employee or consultant and will disclose to the company any ideas he conceives and will assign to the company any inventions he develops. For one year after the termination of the Consulting Agreement, Mr. Parker Sr. will be prohibited from soliciting business from any of the Company’s customers or individuals with which the Company has done business, will not become interested in any business that competes with the Company and will be prohibited from recruiting any employees of the Company.

On April 12, 2008, the Company entered into an amendment to the Consulting Agreement which was effective May 1, 2008 (the “Amendment”). The terms of the Amendment provide for:


	(i)	A monthly payment of $15,000 for May 2008 and monthly payments of $16,000 commencing on June 1, 2008, through and including April 30, 2009, and

	(ii)	coverage under the Company’s medical and dental plans for Mr. Parker Sr. and his spouse through May 31, 2008.

The remaining terms of the Consulting Agreement not amended by the Amendment shall remain in full force and effect, the principal terms of which are:


	(i)	If Mr. Parker Sr. should die during the term of the Amendment, the payments shall continue to be made to his spouse, if she survives him, and if she does not survive him, to Mr. Parker’s beneficiaries.


	(ii)	Mr. Parker Sr. shall be available to represent the Company on the US-Kazakhstan Business Council and assist with marketing efforts utilizing relationships developed during Mr. Parker Sr.’s tenure with the Company;


	(iii)	Mr. Parker Sr. will be required to maintain the confidentiality of any information he obtains while an employee or consultant during the term of the Consulting Agreement, to disclose and assign to the Company any ideas he conceives and any inventions he develops related to the business of the Company or his consulting with the Company; and

During the term of and 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, becoming interested in any capacity in any business that competes with the Company and will be prohibited from recruiting any employees of the Company.

Mr. Parker Sr. is the father of Robert L. Parker Jr., the Chairman and CEO

Lease Agreements

The Company has leased ranch facilities (three ranches covering a total of 9,369 acres) that provide lodging and conference rooms and for hunting, fishing and other outdoor activities used in connection with marketing and other business purposes, from Robert L. Parker Jr. and from the Robert L. Parker Family Trust (“Trust”). Lease payments to Robert L. Parker Jr. and to the Trust for unlimited access to the ranches including payments for maintenance personnel were $0.9 million per year in 2005 and 2006. The leases were terminated effective December 31, 2006.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 14 —	Related Party Transactions (continued)

Effective January 1, 2007, the Company entered into separate Ranch Lease Agreements under which the Company agreed to pay a daily usage fee/person for utilization of the Cypress Springs Ranch owned by the Trust and the Camp Verde Ranch owned by Robert L. Parker Jr. During 2007, the Company incurred fees of $33,000 pursuant to the Ranch Lease Agreement. These fees were paid in early 2008. During 2008, the Company incured $7,150 of fees related to the Ranch Lease Agreements,

Other Related Party Agreements

During 2008, one of the Company’s directors held the position of executive vice president and chief financial officer of Apache Corporation (“Apache”). During 2008, a subsidiary of Apache paid subsidiaries of the Company a total of $18.2 million for performance of drilling services and provision of rental tools.


Note 15 —	Supplementary Information

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.

At December 31, 2007, accrued liabilities included $12.3 million of deferred mobilization fees, $6.7 million of accrued interest expense, $7.0 million of workers’ compensation liabilities and $21.7 million of accrued payroll and payroll taxes. Other long-term obligations included $1.5 million of workers’ compensation liabilities as of December 31, 2007.


	Quarter
Year 2008	First		Second		Third		Fourth			Total
	(Dollars in Thousands Except Per Share Amounts)
	(Unaudited)

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	$	35,401	$	42,190	$	43,847	$	(62,258	)	$	59,180
Income (loss) from continuing operations	$	23,888	$	22,596	$	18,551	$	(39,477	)	$	25,558
Net income (loss)	$	23,888	$	22,596	$	18,551	$	(39,477	)	$	25,558
Basic earnings per share:(1)
Net income	$	0.22	$	0.20	$	0.17	$	(0.35	)	$	0.23
Diluted earnings per share:(1)
Net income	$	0.21	$	0.20	$	0.16	$	(0.35	)	$	0.23


(1)		As a result of shares issued during the year, earnings per share for 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 15 —	Supplementary Information (continued)


	Quarter
Year 2007	First		Second		Third(2)		Fourth(2)		Total(2)
	(Dollars in Thousands Except Per Share Amounts)
	(Unaudited)

Revenues	$	151,273	$	150,277	$	172,197	$	180,826	$	654,573
Operating gross margin	$	49,507	$	42,881	$	57,394	$	50,939	$	200,721
Operating income	$	60,023	$	36,904	$	50,600	$	43,456	$	190,983
Income from continuing operations	$	29,994	$	16,860	$	22,653	$	34,571	$	104,078
Net income	$	29,994	$	16,860	$	22,653	$	34,571	$	104,078
Basic earnings per share:(1)
Net income	$	0.28	$	0.15	$	0.21	$	0.31	$	0.95
Diluted earnings per share:(1)
Net income	$	0.27	$	0.15	$	0.20	$	0.31	$	0.94


(1)		As a result of shares issued during the year, earnings per share for 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 our 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 FIN 48. See Note 7 for further detail.


Note 17 —	Recent Accounting Pronouncements

In February 2007, the FASB issued SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities”, which permits an entity to choose, at specified election dates, to measure eligible financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. Upfront costs and fees related to items for which the fair value option is elected are recognized in earnings as incurred. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations,” which changes how business acquisitions are accounted. SFAS No. 141R requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction and establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed in a business combination. Certain provisions of this standard will, among other things, impact the determination of acquisition-date fair value of consideration paid in a business combination (including contingent consideration); exclude transaction costs from acquisition accounting; and change accounting practices for acquired contingencies, acquisition-related restructuring costs, in-process research and development, indemnification assets, and tax benefits. SFAS No. 141R is effective for business combinations and adjustments to an acquired entity’s deferred tax asset and liability balances occurring after December 31, 2008. The Company is currently evaluating the future impacts and disclosures of this standard.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51,” which establishes new standards governing the accounting for and reporting of noncontrolling interests (NCI) in partially owned consolidated subsidiaries and the loss of control of subsidiaries. Certain provisions of this standard indicate, among other things, that NCI’s (previously referred

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)


Note 17 —	Recent Accounting Pronouncements (continued)

to as minority interests) be treated as a separate component of equity, not as a liability; that increases and decrease in the parent’s ownership interest that leave control intact be treated as equity transactions, rather than as step acquisitions or dilution gains or losses; and that losses of a partially owned consolidated subsidiary be allocated to the NCI even when such allocation might result in a deficit balance. This standard also requires changes to certain presentation and disclosure requirements. SFAS No. 160 is effective beginning January 1, 2009. The provisions of the standard are to be applied to all NCI’s prospectively, except for the presentation and disclosure requirements, which are to be applied retrospectively to all periods presented. The Company is currently evaluating the future impacts and disclosures of this standard.

In May 2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We will adopt the provisions of FSP APB 14-1 on January 1, 2009 and will be required to retroactively apply its provisions, which means we will restate our consolidated financial statements for prior periods.

In applying this FSP, we estimate approximately $31.5 million of the carrying value of the convertible notes to be reclassified to equity as of the July 2007 issuance date. This amount represents the equity component of the proceeds from the notes, calculated assuming a 7.16% non-convertible borrowing rate. The discount will be accreted to interest expense over the five-year term of the notes. Accordingly, approximately $3.1 million of additional non-cash interest expense, or $.02 per diluted share, will be recorded in 2007 and approximately $6.3 million of additional non-cash interest expense will be recorded in 2008. We estimate that diluted income per share for 2009 will decrease by approximately $.04 per diluted share.


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 in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of December 31, 2008. 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 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 Act Rules 13a-15(f) and 15d-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, 2008 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, 2008.

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 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009. Such information is incorporated herein by reference.

Information with respect to executive officers is shown in Item 1 of this Form 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 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009 and is incorporated herein by reference.

The information in the Company’s 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009 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 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 at http://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 report on Form 8-K within four days.


ITEM 11.	*EXECUTIVE COMPENSATION*

The information under the captions “Executive Compensation,” “Fees and Benefit Plans for Non-Employee Directors,” “2009 Director Compensation Table,” “Option/SAR Grants in 2008 to Non-Employee Directors,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Company’s 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009 is incorporated herein by reference.


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

The information required by this item is hereby incorporated by reference from the information appearing under the captions “Security Ownership of Officers, Directors and Principal Shareholders” and “Equity Compensation Plan Information” in the Company’s 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009.


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 2009 Proxy Statement for the Annual Meeting of Shareholders to be held on April 21, 2009.


ITEM 14.	*PRINCIPAL ACCOUNTING FEES AND SERVICES*

The information required by this item is hereby incorporated by reference from 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 2009 Proxy Statement for the Annual Meeting of the Shareholders to be held on April 21, 2009.

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

Reports of Independent Registered Public Accounting Firms		49
Consolidated Statement of Operations for the years ended December 31, 2008, 2007 and 2006		52
Consolidated Balance Sheet as of December 31, 2008 and 2007		53
Consolidated Statement of Cash Flows for the years ended December 31, 2008, 2007 and 2006		55
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006		57
Notes to the Consolidated Financial Statements		58

(2) Financial Statement Schedule:


Report of KPMG LLP — Independent Registered Public Accounting Firm		49
Schedule II — Valuation and qualifying accounts		104

(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 Report on Form 10-Q for the period ended September 20, 2007).
3(b)	—	By-Laws of the Company, as amended on January 31, 2003 (incorporated by reference to the Company’s Form 10-K/A dated September 25, 2003).
4(a)	—	Rights Agreement dated as of July 14, 1998, between the Company and Norwest Bank Minnesota, N.A., as rights agent (incorporated by reference to Form 8-A filed July 15, 1998).
4(b)	—	Amendment No. 1 to the Rights Agreement dated September 22, 1998, between the Company and Norwest Bank Minnesota, N.A., as rights agent (incorporated by reference to Exhibit 3(a) of Form 10-K dated March 17, 2003).
4(c)	—	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 S-4 Registration Statement No. 333-110374 dated November 10, 2003).
4(d)	—	Credit Agreement among Parker Drilling Company, as Borrower, the Several Lenders Parties thereto, Lehman Brothers, Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America, N.A., as Syndication Agent and Lehman Commercial Paper, Inc. as Administrative Agent dated December 20, 2004 (incorporated by reference to Exhibit 99.1 to Form 8-K dated December 27, 2004).
4(e)	—	First Amendment to the Credit Agreement dated December 20, 2004 among Parker Drilling Company, as Borrower, the Several Lenders Parties thereto, Lehman Brothers, Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America, N.A., as Syndication Agent and Lehman Commercial Paper, Inc., as Administrative Agent dated March 1, 2006 (incorporated by reference to Exhibit 4(j) to Form 10-K, dated March 10, 2006).

100


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)*


EXHIBIT
NUMBER		DESCRIPTION

4(f)	—	Second Amendment to the Credit Agreement dated December 20, 2004 among Parker Drilling, as Borrower, the Several Lenders Parties thereto, Lehman Brothers, Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America, N.A., as Syndication Agent dated February 9, 2007 (incorporated by reference to Exhibit 10(c) to annual report on Form 10-K for the year ended December 31, 2006).
4(g)	—	Indenture dated as of September 2, 2004, between the Company and JP-Morgan Chase Bank, as trustee, respecting the $150.0 million Senior Floating Rate Notes due 2010 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K, dated September 7, 2004).
4(h)	—	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 on Form 8-K filed on July 5, 2007)
4(i)	—	Form of 2.125% Convertible Senior Note due 2013 (included in Exhibit 4(h))
4(j)	—	Amended and Restated Credit Agreement, dated as of September 20, 2007, among Parker Drilling Company, as Borrower, the several lenders from time to time thereto, Lehman Brothers Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America N.A., as Syndication Agent, and Lehman Commercial Paper Inc., as Administrative Agent (incorporated by reference to Exhibit 10.1 to report on Form 8-K dated September 25, 2007).
4(k)	—	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 report on Form 8-K dated May 21, 2008.
10(a)	—	Amended and Restated Parker Drilling Company Stock Bonus Plan, effective as of January 1, 1999 (incorporated herein by reference to Exhibit 10(a) to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 1999).*
10(b)	—	Parker Drilling Company Incentive Compensation Plan, dated December 17, 2008, and effective January 1, 2008.*
10(c)	—	1994 Parker Drilling Company Limited Deferred Compensation Plan (incorporated herein by reference to Exhibit 10(h) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(d)	—	1994 Non-Employee Director Stock Option Plan (incorporated herein by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(e)	—	1994 Executive Stock Option Plan (incorporated herein by reference to Exhibit 10(j) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(f)	—	Parker Drilling Company and Subsidiaries 1991 Stock Grant Plan (incorporated by reference to Exhibit 10(c) to Form 10-K dated November 2, 1992).*
10(g)	—	Third Amended and Restated Parker Drilling 1997 Stock Plan effective July 24, 2002 (incorporated herein by reference to Exhibit 10(e) to Annual Report on Form 10-K dated March 20, 2003).*
10(h)	—	2005 Long Term Incentive Plan (“2005 LTIP”) (incorporated by reference to the Company’s 2005 Proxy Statement dated March 22, 2005).*
10(i)	—	First Amendment to the 2005 LTIP (incorporated by reference to the Company’s 2008 Proxy Statement dated March 21, 2008).*
10(j)	—	Second Amendment to the 2005 LTIP, dated December 13, 2008.*
10(k)	—	Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company, dated on or about October 15, 2002 (incorporated by reference to Exhibit 10(g) to Form 10-K dated March 12, 2004).*

101


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)*


EXHIBIT
NUMBER		DESCRIPTION

10(l)	—	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 Form 10-K dated March 17, 2003).*
10(m)	—	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 Form 10-K dated March 14, 2005).*
10(n)	—	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 Form 10-K dated March 14, 2005).*
10(o)	—	Form of Restricted Stock Award Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.2 to Form 8-K dated May 1, 2005).*
10(p)	—	Form of Performance Based Restricted Stock Award Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.3 to Form 8-K dated May 1, 2005).*
10(q)	—	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 Form 10-Q dated August 6, 2004).*
10(r)	—	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 Form 10-Q dated August 6, 2004).*
10(s)	—	Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated April 12, 2006 (incorporated by reference to Exhibit 10.1 to the Form 8-K dated April 12, 2006).*
10(t)	—	Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., dated April 12, 2008.*
10(u)	—	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 under Indenture dated the 23rd day of July 1993, dated April 12, 2006 (incorporated by reference to Exhibit 10.2 to the Form 8-K dated April 12, 2006).*
10(v)	—	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 on Form 8-K filed on July 5, 2007).
10(w)	—	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 on Form 8-K filed on July 5, 2007).
10(x)	—	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 on Form 8-K filed on July 5, 2007).
10(y)	—	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 on Form 8-K filed on July 5, 2007).
10(z)	—	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 on Form 8-K filed on July 5, 2007).
10(aa)	—	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 on Form 8-K filed on July 5, 2007).
10(bb)	—	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 on Form 8-K filed on July 5, 2007).
10(cc)	—	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 on Form 8-K filed on July 5, 2007).

102


ITEM 15.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)*


EXHIBIT
NUMBER		DESCRIPTION

10(dd)	—	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 on Form 8-K filed on July 5, 2007).
21	—	Subsidiaries of the Registrant.
23.1	—	Consent of KPMG LLP — Independent Registered Public Accounting Firm
23.2	—	Consent of PricewaterhouseCoopers LLP — Independent Registered Public Accounting Firm
31.1	—	Robert L. Parker Jr., Chairman 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	—	Robert L. Parker Jr., Chairman 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.

103

PARKER DRILLING COMPANY AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)


	Balance		Charged
	at		to cost			Charged						Balance
	beginning		and			to other						at end of
Classifications	of year		expenses			accounts			Deductions			year

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
Year ended December 31, 2006:
Allowance for doubtful accounts and notes	$	1,639	$	—		$	—		$	158		$	1,481
Reduction in carrying value of rig materials and supplies	$	3,451	$	1,200		$	—		$	314		$	4,337
Deferred tax valuation allowance	$	—	$	—		$	18,026	(1)	$	18,026	(2)	$	—


(1)		During 2006 and prior to the reversal of the state valuation allowance, the Company completed a process of reconciling its Louisiana state income tax balance sheet for the purpose of properly adjusting its deferred tax assets and liabilities. As a result of this process, the Company recognized an additional net deferred tax asset of approximately $18.0 million. Additionally, the Company increased its valuation allowance by $18.0 million resulting in no impact to the net deferred tax asset.

(2)		This deduction relates to the reversal of the valuation allowance related to Louisiana state net operating loss carryforwards and other deferred tax assets resulting from the Company’s return to profitability in Louisiana and expected future earnings performance.

104

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PARKER DRILLING COMPANY


	By:	/s/ Robert L. Parker Jr

Robert L. Parker Jr.

Chairman, Chief Executive Officer and Director

Date: February 27 , 2009

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.	Chairman, Chief Executive Officer and Director (Principal Executive Officer)	February 27, 2009


By:	/s/ James W. Whalen James W. Whalen	Vice Chairman of the Board and Director	February 27, 2009


By:	David C. Mannon David C. Mannon	President and Chief Operating Officer	February 27, 2009


By:	/s/ W. Kirk Brassfield W. Kirk Brassfield	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2009


By:	/s/ Lynn G. Cullom Lynn G. Cullom	Controller (Principal Accounting Officer)	February 27, 2009


By:	/s/ George J. Donnelly George J. Donnelly	Director	February 27, 2009


By:	/s/ John W. Gibson, Jr. John W. Gibson, Jr.	Director	February 27, 2009


By:	/s/ Robert W. Goldman Robert W. Goldman	Director	February 27, 2009


By:	/s/ Gary R. King Gary R. King	Director	February 27, 2009


By:	/s/ Robert E. McKee III Robert E. McKee III	Director	February 27, 2009


By:	/s/ Roger B. Plank Roger B. Plank	Director	February 27, 2009


By:	/s/ R. Rudolph Reinfrank R. Rudolph Reinfrank	Director	February 27, 2009

105

INDEX TO EXHIBITS


EXHIBIT
NUMBER				DESCRIPTION

	10(b)		—	Parker Drilling Company Incentive Compensation Plan dated December 17, 2008, and effective January 1, 2008
	10(j)		—	Second Amendment to the 2005 LTIP, dated December 13, 2008.
	10(t)		—	Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated April 12, 2008
	21		—	Subsidiaries of the Registrant
	23	.1	—	Consent of KPMG LLP — Independent Registered Public Accounting Firm
	23	.2	—	Consent of PricewaterhouseCoopers LLP — Independent Registered Public Accounting Firm
	31	.1	—	Robert L. Parker Jr., Chairman 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	—	Robert L. Parker Jr., Chairman and Chief Executive Officer, Section 1350 Certification.
	32	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.


			PAGE

PART I
	Item 1.	Business		1
	Item 1A.	Risk Factors		10
	Item 1B.	Unresolved Staff Comments		23
	Item 2.	Properties		23
	Item 3.	Legal Proceedings		25
	Item 4.	Submission of Matters to a Vote of Security Holders		25

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
	Item 6.	Selected Financial Data		27
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		46
	Item 8.	Financial Statements and Supplementary Data		47
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		97
	Item 9A.	Controls and Procedures		97
	Item 9B.	Other Information		98

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		99
	Item 11.	Executive Compensation		99
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		99
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		99
	Item 14.	Principal Accounting Fees and Services		99

PART IV
	Item 15.	Exhibits and Financial Statement Schedules		100
Signatures				105
EX-10.B
EX-10.I
EX-10.T
EX-21
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2


ITEM 8.	*FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA*


	•	Note 1: Summary of Significant Accounting Policies — The business segment reference has been revised to reflect the new segment.

	•	Note 12: Business Segments