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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, 2007


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 þ No o

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

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, 2007 was $1,156 million. At January 31, 2008, there were 111,916,159 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 24, 2008 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 2007 revenues are derived from three segments:

	•		U.S. barge drilling;

	•		international land drilling and offshore barge drilling; and

	•		drilling-related rental tools.

We also provide non-capital intensive services such as Front End Engineering and Design (“FEED”) 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.

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, 2007, our fleet of rigs consisted of:

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

	•		nine land rigs in the Asia Pacific region (one rig sold in early 2008);

	•		eight land rigs in the Americas region;

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

	•		seven land rigs in the Africa/Middle East region, including four in our 50 percent-owned joint venture in Saudi Arabia;

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

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

ITEM 1. BUSINESS (continued)

Our Rental Tools Business

One of our subsidiaries, 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.

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 in the shallow water transition zones, primarily in 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 oil 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 drilling equipment and considerable experience to drill. Typically, our international contracts include extended, multi-year terms.

Our Strategy

Our strategy is to maintain and leverage our position as a leading provider of drilling, project management 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. In 2006, we completed the construction of a 3,000 Horsepower (“HP”) barge rig designed specifically for deep well programs in the U.S. Gulf of Mexico. 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 2007 the third and fourth rigs were delivered to Mexico. In addition, during 2007 we began 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 contracted for work in Kazakhstan and is expected to begin mobilization in mid-March 2008. The second rig will be completed in mid-2008 and is currently being marketed internationally.

ITEM 1. BUSINESS (continued)

Our Strategy (continued)

We continue to grow non-capital intensive projects and in April 2008 BP will present to its board for sanctioning the award to a Parker subsidiary of an Engineering, Procurement, Construction and Installment (“EPCI”) contract to construct a BP-owned rig for the ERD (extended reach drilling) development of the Liberty field in Alaska. When completed, this rig will have the capability to drill extended reach wells that exceed current records. We are also developing Front End Engineering & Design (“FEED”) project management services.

In April 2007, Quail Tools’ new rental tools facility opened in Texarkana, Texas. As a result of increased activity at our satellite operation in Williston, North Dakota, we elected to expand this location to a full-scale facility as well, which opened in January 2008.

Sustaining the High Utilization of Our Barge and Land Rigs. We sustain the high utilization of our barge and land rigs by building and upgrading our fleet of premium rigs that will be utilized 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”.

Continuing to Reduce Our Debt to Capitalization Ratio and Enhance Our Liquidity. Our long-term goal is to reduce our debt to capitalization ratio to be in the 30 percent range. Since the establishment of this goal, we have reduced the ratio to 41 percent from a high of 76 percent.

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, China, Colombia, Indonesia, Kazakhstan, Kuwait, Libya, Mexico, New Zealand, Papua New Guinea, Russia, Saudi Arabia, 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 44 percent of our total revenues in the twelve months ended December 31, 2007. Our core international land drilling operations focus primarily in the CIS region, where we have eight land rigs; the Asia Pacific region, where we currently have nine land rigs; Latin America, where we are operating eight land rigs and seven land rigs in Africa & Middle East. Our international offshore drilling operations focus on the Caspian Sea, where we own and operate the world’s largest arctic-class barge rig; and Mexico, where we have one barge rig. We also have 13 drilling and three workover barge rigs in the shallow water transition zones of the U.S. Gulf of Mexico.

Outstanding Safety, Preventive Maintenance, Inventory Control and Training Programs. We have an outstanding safety record. In 2007, 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 management systems, preventive 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.

ITEM 1. BUSINESS (continued)

Our Competitive Strengths (continued)

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 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 is quickly establishing 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 the world’s longest extended reach well 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. With this rig design, BP plans to drill extended-reach wells, some of which are expected to extend to nominal measured depths in excess of 40,000 feet, from one of its existing facilities to the Liberty field offshore location. As noted above, a decision on the award of the EPCI contract to construct and operate this rig as a follow up to our design is anticipated to occur in April 2008.

We also provided labor services on third party-owned drilling rigs in Kuwait, Papua New Guinea and China in 2007.

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.

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 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 land and offshore markets, our experience in operating in challenging environments has been a significant factor in securing contracts. We believe that the market for drilling contracts, both land and offshore, 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.

ITEM 1. BUSINESS (continued)

Customers

Our drilling and rental tools customer base consists of major, independent and national oil and gas companies and integrated service providers. In 2007, ExxonMobil (including subsidiaries and joint ventures) accounted for approximately 11 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 41 percent of our total revenues in 2007.

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. In many cases we are able to obtain an early termination fee if the operator terminates a contract before the end of the term without cause.

Rental tools contracts are typically on a dayrate basis with rates based on type of equipment, investment and competition.

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,
	2007		2006
International drilling		2,055		1,574
U.S. drilling		558		631
Rental tools		255		217
Corporate and other		219		206

Total employees		3,087		2,628

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 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 Gulf Coast market. 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.

The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. 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”), 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.

ITEM 1. BUSINESS (continued)

Environmental Considerations (continued)

The OPA liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place and functioning as an offshore facility. If operating as a vessel, liability limits of $600 per gross ton or $0.5 million, whichever is greater, apply. If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil on or above the water surface, with liability limits of $1,200 per gross ton or $10.0 million, whichever is greater. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actually incurred by a governmental entity for actual or threatened oil discharges associated with any Outer Continental Shelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.

Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility for offshore facilities and vessels in excess of 300 gross tons (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels. The OPA requires owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal Outer Continental Shelf waters, with higher amounts, up to $150.0 million, in certain limited circumstances where the U.S. Minerals Management Service believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. For “tank vessels,” as our offshore drilling rigs are typically classified, the OPA requires owners and operators to demonstrate financial responsibility in the amount of their largest vessel’s liability limit, as those limits are described in the preceding paragraph. A failure to comply with ongoing requirements or inadequate cooperation in a spill may even subject a responsible party to civil or criminal enforcement actions.

In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

All of our operating U.S. 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.

ITEM 1. BUSINESS (continued)

Environmental Considerations (continued)

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 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.

ITEM 1. BUSINESS (continued)

Financial Information About Industry Segments And Geographic Areas

We operate in three segments, U.S. drilling, international drilling and rental tools. Information about our business segments and operations by geographic areas for the years ended December 31, 2007, 2006 and 2005 is set forth in Note 12 in the notes to the consolidated financial statements included in Item 8 of this report.

EXECUTIVE OFFICERS

Officers are elected each year by the board of directors following the annual meeting for a term of one year and until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:

	(1)		Robert L. Parker Jr., 59, 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, 50, 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 1988 through 2003, Mr. Mannon held various positions, including president and chief executive officer of Triton Engineering Services Company, a subsidiary of Noble Drilling. From 1980 through 1988, Mr. Mannon served SEDCO-FOREX, formerly SEDCO, as a drilling engineer.

	(3)		W. Kirk Brassfield, 52, 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, 58, vice president of engineering, joined Parker Drilling in 2000. Mr. Graham was previously the senior vice president of technical services for Diamond Offshore Inc., an international offshore drilling contractor. His experience with Diamond Offshore ranged from 1978 through 1999 in the areas of offshore drilling rig design, new construction, conversions, marine operations, maintenance and regulatory compliance.

	(5)		Ronald C. Potter, 54, vice president and general counsel, re-joined Parker Drilling in June 2003. From 2001 through May 2003, Mr. Potter was our 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, 53, principal accounting officer and corporate controller, joined Parker Drilling in August 2004 as director of corporate planning. From March 2001 through August 2004, Ms. Cullom served in various accounting and reporting director positions at El Paso Corporation. 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, 52, vice president, operations, joined Parker Drilling in December 2005. 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)

Other Parker Drilling Company Officer

(8)

David W. Tucker, 52, treasurer and director of investor relations, 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 and assumed the responsibilities of director of investor relations in 2002.

ITEM 1A. RISK FACTORS

The contract drilling 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

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. Additionally, we are making substantial expenditures for the construction of new rigs consistent with our strategy to construct a fleet of premium rigs that will operate continuously despite market fluctuations. 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;

	•		delays relating to inaccessibility of credit markets;

	•		long lead times for manufactured rig components;

	•		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 liquidated damages associated with 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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, as the demand for drilling services and the size of the worldwide rig fleet has recently increased, it has become more difficult to retain existing personnel and shortages of qualified personnel have arisen, which could create upward pressure on wages and prevent us from retaining or attracting qualified personnel in a cost-effective manner.

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

As of December 31, 2007, we had:

	•		$353.7 million of long-term debt;

	•		$20.0 million of current revolver debt;

	•		$8.5 million of operating lease commitments; and

	•		$12.9 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 by financial, business and other factors affecting our operations, many of which are beyond our control, and some of which are specified below.

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 documentation contained in our existing debt instruments. In addition, 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

Our debt and the covenants contained in the instruments governing our debt could have important consequences to you. For example, it 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 2008 will be approximately $150.0 — $165.0 million, including approximately $75.0 million for maintenance projects). We may require additional capital in the event of significant departures from our current business plan or unanticipated expenses. For example, although we are appealing the amount of assessed interest, as described in Note 13, Commitments and Contingencies, “Kazakhstan Tax Case” in Item 8 of this Form 10-K, we may be required to pay $33 million in interest within the next few months. In addition, we may make additional cash contributions to complete the drilling rigs and for on-going operations of our Saudi Arabia joint venture. See Note 8, Saudi Arabia Joint Venture. Sources of funding for our future capital requirements may include any or all of the following:

	•		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 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 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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 economic activity, which affects levels of consumer demand;

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

	•		the availability of pipeline capacity; and

	•		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. Although drilling conditions are currently favorable, in the event the market becomes depressed, customers are more likely to seek renegotiation of contract terms or to exercise their termination rights.

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 2007, ExxonMobil accounted for approximately 11 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 41 percent of our total revenues in 2007. 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 remains strong, demand in the Gulf of Mexico barge market has softened slightly 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 remain strong for the foreseeable future. However, if commodity prices decline or other factors adversely affect demand for drilling activity, our utilization rates and financial performance will be adversely affected. 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 new rig construction programs in place as a result of recent energy price levels. In many markets in which we operate, the number of rigs available has historically exceeded the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. 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.

The improved industry conditions due to increased demand for oil and natural gas has spurred a significant increase in the construction of drilling rigs. As the supply of rigs increases over the next few years, there is a significant risk that this could result in a reduction of utilization and dayrates, which would adversely affect our business and financial performance.

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

We have operations in 13 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 2007, we derived approximately 44 percent of our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, among others:

	•		foreign laws and governmental regulation;

	•		expropriation, confiscatory taxation and nationalization of our assets located in areas in which we operate;

	•		increases in governmental royalties;

	•		import-export quotas;

	•		hiring and retaining skilled and experienced workers, many of which 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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 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 risk.

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 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Business (continued)

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. Our international operations are also subject to risks of terrorism, war, civil disturbances and other political events. 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 deductible for certain losses relating to workers’ compensation, employers’ liability, 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 from 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Common Stock

Market price of our common stock could change significantly.

The market price of our common stock may change 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, including the outcome of our interest dispute with the Ministry of Finance of the Republic of Kazakhstan (see Note 13 in the notes to the consolidated financial statements in Item 8 of this Form 10-K).

A hostile takeover of our Company would be difficult.

We have adopted a stockholders’ rights plan. 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 material direct and indirect domestic subsidiaries; and (ii) 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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to our Debt Securities (continued)

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, 2007, our non-guarantor subsidiaries collectively owned approximately 23 percent of our consolidated total assets and held approximately $20.5 million of our consolidated cash and cash equivalents of approximately $60.1 million. In 2007, our non-guarantor subsidiaries had drilling and rental revenues of approximately $136.3 million and a total operating income of approximately $16.6 million. See Note 5 to the notes to the consolidated financial statements.

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.

ITEM 1A. RISK FACTORS (continued)

Risks Related to our Debt Securities (continued)

We may not be able to repurchase our 9.625% Senior Notes upon a change of control.

Upon the occurrence of specific change of control events affecting us, the holders of our 9.625% Senior Notes will have the right to require us to repurchase our notes at 101 percent of their principal amount, plus accrued and unpaid interest. Our ability to repurchase our notes upon such a change of control event would be limited by our access to funds at the time of the repurchase and the terms of our other debt agreements. Upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our senior secured credit facilities, our notes and other outstanding indebtedness. The source of funds for these repayments would be our available cash or cash generated from other sources. However, we may not have sufficient funds available upon a change of control to make any required repurchases of this outstanding indebtedness.

In addition, the change of control provisions in the indenture governing our 9.625% Senior Notes may not protect the holders of our notes from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a “Change of Control” under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change that constitutes a “Change of Control” as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a “Change of Control” as defined in the indenture, we will not be required to make an offer to repurchase the notes and the holders may be required to continue to hold their notes despite the event.

We may not have sufficient cash to repurchase the 2.125% Convertible Senior Notes at the option of the holder upon a fundamental change or to pay the cash payable upon a conversion.

Upon the occurrence of a fundamental change as defined in the indenture governing our 2.125% Convertible Senior Notes, subject to certain conditions, we will be required to make an offer to repurchase for cash all outstanding notes at 100% 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:

	•		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;

	•		entering into joint venture agreements with local companies;

	•		our future capital expenditures and investments in the acquisition and refurbishment of rigs and equipment, including the rigs being constructed by our Saudi Arabia joint venture;

	•		our future liquidity;

	•		availability and sources of funds to reduce our debt and expectations of when debt will be reduced;

	•		the outcome of pending and future legal proceedings, tax assessments and other claims, including the outcome of our interest dispute with the Ministry of Finance of the Republic of Kazakhstan;

	•		the availability of insurance coverage for pending or future claims;

	•		the enforceability of contractual indemnification in relation to pending or future claims;

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

	•		organic growth of our operations.

ITEM 1A. RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS (continued)

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;

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

	•		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 tax laws or ability to remit funds to the U.S., that adversely affect the cost of doing business;

	•		adverse environmental events;

	•		adverse weather conditions;

	•		changes in the concentration of customer and supplier relationships;

	•		unexpected cost increases for upgrade and refurbishment projects;

	•		delays in obtaining components for capital projects;

	•		shortages of skilled labor;

	•		unanticipated cancellation of contracts by operators without cause;

	•		breakdown of equipment and other operational problems;

	•		changes in competition; 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 (continued)

Barge Rigs (continued)

The following table presents our utilization rates and rigs available for service for the years ended December 31, 2007 and 2006.


	Year Ended December 31,
	2007			2006
Transition Zone Rig Data
U.S. barge deep drilling:
Rigs available for service (1)		10.0			9.6
Utilization rate of rigs available for service (2)		95	%		81	%

U.S. barge intermediate drilling:
Rigs available for service (1)		3.3			4.0
Utilization rate of rigs available for service (2)		70	%		72	%

U.S. barge workover and shallow drilling:
Rigs available for service (1)		3.0			5.4
Utilization rate of rigs available for service (2)		30	%		53	%

International barge drilling:
Rigs available for service (1)		2.0			3.2
Utilization rate of rigs available for service (2)		100	%		100	%

U.S. Land Rig Data
Rigs available for service (1):		1.6			0.8
Utilization rate of rigs available for service (2):		55	%		80	%

International Land Rig Data
Rigs available for service (1):		25.8			23.1
Utilization rate of rigs available for service (2):		73	%		63	%


(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 2007.

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, 2007. 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,
	2007			2006 (1)			2005 (2)			2004			2003(3)
	(Dollars in Thousands, Except Per Share Amounts)
Income Statement Data
Total drilling and rental revenues	$	654,573		$	586,435		$	531,662		$	376,525		$	338,653

Total operating income		190,983			143,326			115,123			23,867			22,927

Equity in loss of unconsolidated joint venture and related charges		(27,101	)		—			—			—			—

Other expense		(22,081	)		(25,891	)		(44,895	)		(59,423	)		(58,376	)

Income tax (expense) benefit		(37,723	)		(36,409	)		28,584			(15,009	)		(16,985	)

Income (loss) from continuing operations		104,078			81,026			98,812			(50,565	)		(52,434	)

Net income (loss)		104,078			81,026			98,883			(47,083	)		(109,699	)

Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.95		$	0.76		$	1.03		$	(0.54	)	$	(0.56	)
Net income (loss)	$	0.95		$	0.76		$	1.03		$	(0.50	)	$	(1.17	)

Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.94		$	0.75		$	1.02		$	(0.54	)	$	(0.56	)
Net income (loss)	$	0.94		$	0.75		$	1.02		$	(0.50	)	$	(1.17	)

Balance Sheet Data
Cash and cash equivalents	$	60,124		$	92,203		$	60,176		$	44,267		$	67,765

Marketable securities		—			62,920			18,000			—			—

Property, plant and equipment, net		585,888			435,473			355,397			382,824			387,664

Assets held for sale		—			4,828			—			23,665			150,370

Total assets		1,076,987			901,301			801,620			726,590			847,632

Total long-term debt and capital leases, including current debt		373,721			329,368			380,015			481,063			571,625

Stockholders’ equity		534,724			459,099			259,829			148,917			192,803


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

(2)		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.

(3)		In June 2003, we recognized a $53.8 million impairment charge in discontinued operations related to our plan to sell the U.S. Gulf of Mexico offshore assets. See Note 2 in the notes to the consolidated financial statements.

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

OVERVIEW AND OUTLOOK

Summary— Our business continues to benefit from the favorable market conditions resulting primarily from high commodity prices and worldwide demand. The price of oil has remained at world record levels for the past few years and shows few signs of retreating, unless there is an unanticipated and precipitous reduction in demand, for example, due to a recession affecting multiple countries currently fueling the demand. Natural gas prices have continued to fluctuate and are more susceptible to factors that affect temporal demand, such as weather.

As a contract driller and provider of rental tools, our financial results are largely dependent upon the level of oil and gas exploration and drilling of major, large independent and national oil companies around the world. Due to the sustained high oil prices most operators have increased their budgets and are actively seeking to increase their reserves to meet worldwide demand for oil, primarily in international locations. As part of our strategic initiatives, we strive to deploy our international land rigs to those areas and for those operators that we anticipate will generate long-term profits.

We have upgraded our domestic barge fleet during the past few years to enhance our ability to provide the safest and lowest total well cost drilling service to operators drilling for natural gas in the Gulf of Mexico transition zones. We believe our preferred fleet will continue to generate solid financial results despite moderate softening in natural gas demand.

Overview — Total operating income increased 20 percent over 2006 primarily as a result of continued strong performance from our U.S. Gulf of Mexico operations and rental tools business. Demand in the U.S. for both barge rig and rental tools was consistently high in 2007. International operations grew in the second half of the year as we transitioned to new contracts, with revenues in the last six months of the year $43.7 million (36 percent) higher than in the first half.

Drilling and rental operating income was up 33 percent ($47.7 million), with overall drilling operations utilization at 75 percent, up from 69 percent in 2006. Utilization in the U.S. Gulf of Mexico market was 78 percent compared to 71 percent in 2006, with deep drilling barge utilization at 95 percent. Quail operating profit was also up $3.2 million over 2006 on a revenue increase of $16.0 million. We also benefited from the sale of two workover barges, resulting in a gain of $15.1 million.

In international markets, utilization increased to 88 percent by the end of the year as we commenced operation on substantially all of our new land drilling contracts. At the end of 2007, we had five rigs drilling in Mexico, another rigging up and another moving to location, both of which commenced operation in the first quarter of 2008. Two rigs in Colombia worked most of 2007 after commencing operations in the fourth quarter of 2006. In the CIS region, seven of nine rigs were working by the end of the year. Six of these rigs had completed long-term contracts in 2006.

In our Africa Middle East region, start up of new country operations was slow and difficult. In Libya, we experienced costly shortages of equipment and other start up issues which delayed commencement. Our customer terminated our three-year contract in early January after completion of the first well. In Algeria, we experienced delays in getting the newly constructed rigs into the country and rigged up and incurred significant downtime during the first few months of operations, although both rigs operated throughout the fourth quarter with minimal downtime.

OVERVIEW AND OUTLOOK (continued)

Our 50 percent owned Saudi Arabia joint venture has experienced significant cost overruns due to increases in vendor prices, costs to remedy defects in construction and delays in equipment delivery. Although the joint venture has expended significant non-budgeted costs to commission rigs one through four, the rigs were late in starting drilling operations. The joint venture customer, Saudi Aramco, initially suspended liquidated damages for six months, but began deducting them from the November and December 2007 invoices through a 50 percent reduction of dayrates. At the request of the joint venture, Saudi Aramco subsequently agreed to suspend further deductions pending a resolution of this issue. In the fourth quarter of 2007 we accrued $13.8 million (our 50 percent portion) of liquidated damages. We also recorded $9.8 million in operating losses during the period, and provided a $3.5 million reserve for advances related to the joint venture.

On December 12, 2007, PKD Kazakhstan paid the tax portion of the Income Tax assessment which is described further in Note 13 to the financial statements. The payment was partially funded by drawing $20 million from our revolving credit agreement.

Outlook — We anticipate a continuation of favorable market conditions in 2008. As a result, we expect strong results in 2008 from our international operations as we realize full year benefits of contracts at higher dayrates commencing throughout 2007 in Mexico, Kazakhstan and Turkmenistan. In addition, Rig 267 in Mexico spud in early February and Rig 247, which has been upgraded, is mobilizing for a contract in Kazakhstan and is expected to spud in March 2008. Rig 269, a new build, is expected to begin mobilization in March 2008 and should commence operations in Kazakhstan mid 2008. The contract for our barge rig in the Caspian Sea is up for renewal in April 2008, and we expect to reach an agreement with our customer for a substantial increase in the dayrate. U.S. operations are also projected to continue to provide strong results in 2008 although we expect some softening in utilization and dayrates.

We anticipate our rental tools segment will experience further growth attributable to full-year results of additional capital invested throughout 2007.

In addition, we will continue our BP Liberty FEED project for BP Alaska through the first quarter of 2008, and await the award of the full project which has been presented to its board for sanctioning in April 2008. When completed, this rig will be capable of drilling extended-reach wells of approximately 44,000 feet.

We anticipate continued high operating costs over the next few months for the four rigs currently operating in our Saudi Arabia joint venture due primarily to continued rental of certain components until they are replaced with permanent capital equipment, which is anticipated to be completed by the end of the second quarter 2008. The joint venture also continues to incur significant capital costs associated with the commissioning of the remaining two rigs and is in discussions with Saudi Aramco to resolve the cost issues associated with the project.

Recent Events — On February 25, 2008, the Kazakhstan branch of Parker Drilling Company International Limited, a subsidiary of Parker Drilling, received notice that the Atyrau Economic Court issued a ruling canceling the interest assessment of approximately US$33 million issued by the Ministry of Finance of the Republic of Kazakhstan, which was calculated from the date the revenue was received in 2000, and has ruled that the interest should be recalculated from and after October 2005, the date of the assessment, through December 12, 2007, the date the principal tax was paid. Although this would reduce interest to approximately $13 million, we have not adjusted our reserve, pending final resolution. See Note 13, Commitments and Contingencies, “Kazakhstan Tax Claim” in Item 8 of this Form 10-K.

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. Drilling and rental operating income 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)

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


	Year Ended December 31,
	2007					2006
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling	$	231,139		35	%	$	191,225		33	%
International drilling		285,403		43	%		273,216		46	%
Rental tools		138,031		21	%		121,994		21	%

Total drilling and rental revenues	$	654,573		100	%	$	586,435		100	%


Drilling and rental operating income:
U.S. drilling gross margin excluding depreciation and amortization (1)	$	132,746		57	%	$	107,763		56	%
International drilling gross margin excluding depreciation and amortization (1)		70,124		25	%		53,506		20	%
Rental tools gross margin excluding depreciation and amortization (1)		83,654		61	%		75,540		62	%
Depreciation and amortization		(85,803	)				(69,270	)

Total drilling and rental operating income (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)		Drilling and rental gross margins, excluding depreciation and amortization, are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental gross margin, excluding depreciation and amortization, as a percent of drilling and rental 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 drilling and rental 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:


			International
	U.S. Drilling		Drilling		Rental Tools
	(Dollars in Thousands)
Year Ended December 31, 2007
Drilling and rental operating income (2)	$	99,514	$	41,943	$	59,264
Depreciation and amortization		33,232		28,181		24,390

Drilling and rental gross margin excluding depreciation and amortization	$	132,746	$	70,124	$	83,654


Year Ended December 31, 2006
Drilling and rental operating income (2)	$	83,370	$	27,465	$	56,704
Depreciation and amortization		24,393		26,041		18,836

Drilling and rental gross margin excluding depreciation and amortization	$	107,763	$	53,506	$	75,540


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

RESULTS OF OPERATIONS (continued)

U.S. Drilling Segment

Revenues for the U.S. drilling segment increased $39.9 million to $231.1 million for the year ended December 31, 2007 as compared to the year ended December 31, 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 and we had an additional $5.6 million related to engineering services contracts.

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 $25.0 million to $132.7 million. This increase includes a $1.8 million increase for the engineering services contracts referred to above, partially offset by 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 $12.2 million to $285.4 million during the year ended December 31, 2007. Of this increase, $28.1 million is related to an increase in international land drilling revenues, offset by a $15.9 million decrease in revenues from offshore operations. The decline of $15.9 million in offshore operations is due primarily to the sale of our barge rigs in Nigeria in the third quarter of 2006.

In our Americas region, land drilling revenues in Mexico increased $6.7 million to $23.4 million due to higher dayrates under the new contracts entered into in 2007 and higher utilization. In Colombia, revenues were $35.0 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.

Land revenues in the CIS decreased by $10.7 million as a result of:

	•		completion of the two-rig, TCO contract in 2006 ($30.9 million);

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

	•		a reduction in revenues related to 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).

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 $11.5 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).

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

Gross margin, excluding depreciation and amortization, for international land operations increased by $12.1 million. In Mexico, gross margin, excluding depreciation and amortization, improved by $13.9 million due to higher dayrates under new contracts and to lower expenses in 2007, as 2006 included costs to close down operations and relocate seven rigs outside Mexico. In Colombia, gross margin, excluding depreciation and amortization, increased by $15.9 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.

The increases were partially offset by $9.8 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 $4.8 million for the year. 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.

International offshore revenues declined $15.9 million to $34.9 million during the year ended 2007 compared to 2006. This decrease was due primarily to the sale of our Nigerian barge rigs in the third quarter of 2006. Revenues for Barge Rig 53 in Mexico increased $4.1 million due to a higher dayrate. Gross margins, excluding depreciation and amortization, for international offshore operations increased $4.5 million as a result of the higher dayrate in Mexico combined with lower costs in the Caspian Sea, partially offset by the sale of the Nigeria barge rigs.

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.

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

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.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

We recorded net income of $81.0 million for the year ended December 31, 2006, as compared to net income of $98.9 million for the year ended December 31, 2005. The 2006 results reflect a reversal of a $12.6 million valuation allowance and the current year utilization of $5.4 million of net operating loss (“NOL”) carryforwards, both related to Louisiana state NOL carryforwards. Included in 2005 net income was $71.5 million related to the reversal of a valuation allowance related to our federal NOL. Drilling and rental operating income was $167.5 million for the year ended December 31, 2006, as compared to $122.3 million for the year ended December 31, 2005. Gain on disposition of assets was $7.6 million for the 2006 period as compared to $25.6 million for the 2005 period.

RESULTS OF OPERATIONS (continued)

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


	Year Ended December 31,
	2006					2005
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling	$	191,225		32	%	$	128,252		24	%
International drilling		273,216		47	%		308,572		58	%
Rental tools		121,994		21	%		94,838		18	%

Total drilling and rental revenues	$	586,435		100	%	$	531,662		100	%


Drilling and rental operating income:
U.S. drilling gross margin excluding depreciation and amortization (1)	$	107,763		56	%	$	61,425		48	%
International drilling gross margin excluding depreciation and amortization (1)		53,506		20	%		71,411		23	%
Rental tools gross margin excluding depreciation and amortization (1)		75,540		62	%		56,627		60	%
Depreciation and amortization		(69,270	)				(67,204	)

Total drilling and rental operating income (2)		167,539					122,259

General and administrative expense		(31,786	)				(27,830	)
Provision for reduction in carrying value of certain assets		—					(4,884	)
Gain on disposition of assets, net		7,573					25,578

Total operating income	$	143,326				$	115,123


(1)		Drilling and rental gross margins, excluding depreciation and amortization, are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental gross margin excluding depreciation and amortization as a percent of drilling and rental 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 drilling and rental 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:


			International
	U.S. Drilling		Drilling		Rental Tools
	(Dollars in Thousands)
Year Ended December 31, 2006
Drilling and rental operating income (2)	$	83,370	$	27,465	$	56,704
Depreciation and amortization		24,393		26,041		18,836

Drilling and rental gross margin excluding depreciation and amortization	$	107,763	$	53,506	$	75,540


Year Ended December 31, 2005
Drilling and rental operating income (2)	$	41,739	$	40,281	$	40,239
Depreciation and amortization		19,686		31,130		16,388

Drilling and rental gross margin excluding depreciation and amortization	$	61,425	$	71,411	$	56,627


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

RESULTS OF OPERATIONS (continued)

U.S. Drilling Segment

Revenues for the U.S. drilling segment increased $63.0 million to $191.2 million as compared to the year ended December 31, 2005. The increased revenues were primarily due to a $55.6 million increase for our barge drilling operations where we had higher dayrates, that more than offset lower utilization. Barge Rig 12 was undergoing an upgrade from workover to deep drilling status until late May and we also had maintenance and upgrade time for Barge Rigs 8, 54 and 50. Newly constructed Barge Rig 77 also began operations in December 2006. During the last half of 2006 we also repositioned two international land rigs into the U.S. market which contributed $7.1 million to the increase in U.S. drilling segment revenues.

As of December 31, 2006 this segment consisted of 19 barge rigs: ten deep drilling barge rigs, four intermediate drilling barge rigs and five workover barge rigs; and two land rigs. Two of the workover barge rigs were reflected as assets held for sale as of December 31, 2006 and were sold in early January 2007. See Note 2.

Average dayrates for the deep drilling barge rigs increased approximately $14,300 per day in 2006 as compared to 2005. As a result of approximately 46 percent higher dayrates on all barge rigs, the addition of two land rigs and effective operating cost controls, gross margins, excluding depreciation and amortization increased $46.3 million to $107.8 million. Gross margin percentages excluding depreciation and amortization increased from 48 percent during the year ended 2005 to 56 percent during the year ended of 2006. This increase included $3.6 million for the two land rigs discussed above as compared to 2005 which included start up costs for the barge Rig 72 transition from Nigeria.

International Drilling Segment

International drilling revenues decreased $35.4 million to $273.2 million during the year ended December 31, 2006 as compared to the year ended December 31, 2005 due to the completion of long term contracts and the transition to new contracts throughout the year. International land drilling revenues decreased $24.4 million and offshore operations declined $11.0 million.

The international land drilling revenues decrease was attributable primarily to completion of contracts in Mexico ($33.5 million), Kazakhstan TCO contract ($20.1 million), and the partial completion of our contracts in Turkmenistan ($1.9 million), resulting in the release of two of three rigs, and New Zealand ($1.8 million) due to downtime for Rig 188 in the second quarter of 2006. The sale in 2005 of rigs in Colombia and Peru also caused a decline of $4.3 million in revenues. These decreases were partially offset by increases from new international land contracts, a portion of which are attributable to release of above mentioned rigs that were re-located to other operating areas.

In the CIS region, the overall decline in land drilling revenues during the year ended 2006 was $7.9 million. Declines included the Kazakhstan-TCO project completion ($20.1 million), the completion of wells for two rigs in Turkmenistan ($1.9 million), mentioned above and a decline of $0.7 million in Russia as the result of contract completion in mid-2005. Revenues increased $10.9 million in the CIS region for our O&M contracts. Our Orlan project contributed $4.6 million to the increase as the contract was fully operational for the entire year in 2006 and our Rig 262 Sakhalin Island project contributed $6.3 million, as both dayrates and services provided increased. In the Karachaganak area of Kazakhstan, revenues increased by $3.9 million due to the addition of Rig 107 (which was transitioned from the TCO project), which began drilling in late March 2006.

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

An increase in revenue of $13.4 million in Papua New Guinea was the result of the operation of two full O&M contracts for the year ended in 2006, whereas they were only labor contracts in 2005 with full O&M operations not commencing until late in the third quarter of 2005. Also, Rig 140 drilled all of 2006, whereas it did not drill in 2005, and we negotiated a rate increase on Rig 226 effective June 2006. In Indonesia, increased revenues were due to higher utilization as two rigs operated most of 2006, whereas the rigs were on reduced rates until June in 2005. Revenues in Bangladesh increased $7.6 million due to operation of Rig 225 in 2006 whereas operations were suspended due to a well control incident in late June 2005. Revenues were down $1.8 million in New Zealand due primarily to lower operating and reimbursable revenues relating to Rig 188 which was idle during the second quarter of 2006.

International offshore revenues declined $11.0 million to $50.8 million during 2006 as compared to the year ended December 31, 2005. This decrease was due primarily to the reduced force majeure rates applicable to our Nigerian barge rigs during the first quarter of 2006 and the sale of these rigs in the third quarter of 2006 and lower revenues on Rig 257 in the Caspian Sea areas due to maintenance days. This decrease was partially offset by a $1.4 million increase in revenues for our barge rig in Mexico due to higher dayrates.

Gross margin excluding depreciation and amortization for our international operations decreased by $17.9 million due to the completion of contracts in Mexico, TCO, and in Turkmenistan, and as a result of the sale of rigs in Peru and Colombia in the second and third quarters of 2005. These decreases were partially offset by increases on our O&M contracts in the Russian and the CIS regions and increases in Papua New Guinea, where we had higher dayrates for Rig 226, increased contributions from O&M contracts and operation of Rig 140 in 2006.

Rental Tools Segment

Rental tools revenues increased $27.2 million or 28.6 percent to $122.0 million during the year ended December 31, 2006 as compared to 2005. Revenues increased at all U.S. locations as we added new customers and increased rentals from our existing customer and achieved higher rental rates. Rental tools gross margins excluding depreciation and amortization increased $18.9 million, or 33.4 percent, to $75.5 million for the current period as compared to 2005.

Other Financial Data

General and administration expense increased approximately $4.0 million in the year ended 2006 due primarily to additional stock-based compensation expense.

Gain on disposition of assets in 2006 was $7.6 million relating primarily to a gain on the sale of our two barge rigs in Nigeria and final insurance recoveries relating to damage on Rig 255 in Bangladesh and Rig 57 in the U.S. Gulf of Mexico which occurred in 2005. During the year ended December 31, 2005, gain on disposition of assets was $25.6 million, including $13.8 million from our asset sales program that was completed in the third quarter of 2005 and $10.5 million from insurance proceeds on the loss of Rig 255.

Interest expense declined $10.5 million during the year ended December 31, 2006 as compared to 2005 due primarily to the reduction of outstanding debt throughout 2005 of $101.0 million and further reduction of $50.0 million during 2006. In addition, we capitalized $3.6 million of interest related to new rig construction in 2006. Loss on extinguishment of debt declined by $6.3 million as a result of the significant reduction of debt in 2005. Interest income increased $5.7 million due to a higher cash balance in 2006 as compared to 2005, due primarily to proceeds from our stock offering in January 2006, higher cash flow from operations, and higher interest rates.

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

In 2004, we entered into two variable-to-fixed interest rate swap agreements neither of which are still outstanding. 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 currently in earnings. For the year ended December 31, 2006, there was no significant change in the fair value of the derivative positions and for the year ended December 31, 2005, there was a $2.1 million increase in fair value during the year. For additional information see Note 6 in the notes to the consolidated financial statements in Item 8 of this Form 10-K.

Income tax expense from continuing operations was $36.4 million and consisted of U.S. federal current tax expense of $13.0 million and U.S. federal and state deferred tax expense of $17.8 million, current foreign tax expense of $7.6 million and foreign deferred tax benefit of $2.1 million for the year ended December 31, 2006. Income tax benefit from continuing operations is $28.6 million and consists of U.S. federal current tax expense of $1.8 million and U.S. federal deferred benefit of $46.5 million, current foreign tax expense of $14.5 million and foreign deferred tax benefit of $1.6 million for the year ended December 31, 2005. Our effective income tax rates for financial reporting purposes were approximately 31 percent and (41) percent for the years ended December 31, 2006 and 2005, respectively. The 2006 effective tax of 31 percent is higher than 2005 due primarily to the reversal of the Federal 2005 valuation allowance partially offset by the 2006 benefit related to the State NOL carryforwards. The reduction in foreign taxes, net of federal benefit, in 2006 from 2005 relates to a federal tax deduction on actual foreign cash taxes paid versus accrued foreign taxes. The decrease in income tax on foreign corporate income in 2006 is due to the increase in earnings on our domestic corporations. U.S. taxes are provided on the earnings since we do not defer recognition of the foreign corporation’s income under APB No. 23, “Accounting for Income Taxes — Special Areas.”

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

As of December 31, 2007, we had cash, cash equivalents and marketable securities of $60.1 million, a decrease of $95.0 million from December 31, 2006. The primary sources of cash for the twelve-month period as reflected on the consolidated statements of cash flows were $74.3 million provided by operating activities, $109.2 million from the issuance of convertible debt, net of issuance costs and hedge and warrant transactions, a $20.0 million draw on our revolving credit facility and $15.5 million from stock options exercised. The primary use of cash was $152.9 million used in investing activities, including $242.1 million for capital expenditures, a $26.4 million tax payment to Kazakhstan in December 2007, a $5.0 million investment in our Saudi joint venture and a $100.0 million redemption of Senior Floating Rate Notes. Primary sources of cash are insurance proceeds of $7.8 million relating to Rig 247, net proceeds of $20.5 million from the sale of two workover barge rigs and $62.9 million in net proceeds from the sale and purchase of marketable securities. Major capital expenditures for the period included $75.6 million on construction of new land rigs, $11.4 million on rebuilding Rig 247 and $62.0 million for tubulars and other rental tools for the expansion of Quail Tools.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Operating Cash Flows (continued)

As of December 31, 2006, we had cash, cash equivalents and marketable securities of $155.1 million, an increase of $76.9 million from December 31, 2005. The primary sources of cash for the twelve-month period as reflected on the consolidated statements of cash flows were $166.9 million provided by operating activities, $194.7 million used in investing activities and $59.8 million provided by financing activities. Major investing activities during the year ended December 31, 2006 included $195.0 million for capital expenditures. Major capital expenditures for the period included $43.3 million on construction of four new 2,000 HP land rigs, $28.8 million on construction of a new ultra-deep drilling barge, $40.9 million for tubulars and other rental tools for Quail Tools, $10.0 million and $8.5 million on repairs and upgrades on Barge Rigs 50B and 54B, respectively, and $7.4 million on the conversion of workover Barge Rig 12 to a deep drilling barge. We also used $10.0 million to fund our joint venture in Saudi Arabia and $44.9 million of net investment in auction rate securities, partially offset by $46.0 million in proceeds from the sale of two Nigeria barge rigs. Major financing activities for the period included $99.9 million of net proceeds on our common stock issuance in January 2006 and a $50.0 million reduction in debt, net of premium and are further detailed in subsequent paragraphs.

As of December 31, 2005, we had cash, cash equivalents and marketable securities totaling $78.2 million, an increase of $33.9 million from December 31, 2004. The primary sources of cash for the twelve-month period as reflected on the consolidated statement of cash flows were $122.6 million provided by operating activities and $74.9 million of proceeds from the disposition of assets, including insurance proceeds. The primary uses of cash for the year ended December 31,2005 were $69.5 million for capital expenditures and $94.1 million for financing activities. Major capital expenditures for the period included $28.0 million for tubulars and other rental tools for Quail Tools. Our investing activities also include an investment of $18.0 million in auction rate securities which are classified as “Marketable securities” on the consolidated balance sheet. Our financing activities included a net reduction in debt of $100.1 million, which is further detailed in subsequent paragraphs.

Financing Activity

On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125 percent Convertible Senior Notes due July 15, 2012. Interest is payable semiannually on July 15th and January 15th. The initial conversion price is approximately $13.85 per share and is subject to adjustment for the occurrence of certain events stated within the indenture. Proceeds from the transaction were used to redeem our outstanding Senior Floating Rate Notes, to pay the net cost of the hedge and warrant transactions described below, and for general corporate purposes.

In connection with the offering of the Convertible Senior Notes, we also entered into separate convertible note hedge transactions (collectively, the “convertible hedge transactions”) with respect to our common stock with each of Bank of America, N.A., Deutsche Bank AG, London Branch and Lehman Brothers OTC Derivatives Inc. (collectively, the “Hedge Participants”). The convertible hedge transactions cover, subject to customary anti-dilution adjustments, approximately 9.0 million shares of our common stock. Separately and concurrently with entering into the convertible hedge transactions, we also entered into warrant transactions (collectively, the “warrant transactions”) with the Hedge Participants whereby we sold to the Hedge Participants warrants to acquire, subject to customary anti-dilution adjustments, up to approximately 9.0 million shares of our common stock. The convertible hedge and issuer warrant transactions are separate transactions that we have entered into with the Hedge Participants, and they are not part of the terms of the Convertible Senior Notes nor will they affect the holders’ rights under the Convertible Senior Notes. Holders of the Convertible Senior Notes will not have any rights with respect to the convertible hedge and warrant transactions. Effectively, the hedge and warrant transactions increase the conversion price to approximately $18.29 per share.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (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 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 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 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 Convertible Senior Notes was used to fund the redemption.

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.

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.

On February 7, 2005, we redeemed $25.0 million face value of our 10.125% Senior Notes pursuant to a redemption notice dated January 6, 2005 at the redemption price of 105.0625 percent. Proceeds from the sale of jackup Rig 25 and cash on hand were used to fund the redemption.

On April 21, 2005, we issued an additional $50.0 million in aggregate principal amount of our 9.625% Senior Notes due 2013 at a premium. The offering price of 111 percent of the principal amount resulted in gross proceeds of $55.5 million. The $5.5 million premium is reflected as long-term debt and amortized over the term of the notes. The additional notes were issued under an indenture, dated as of October 10, 2003, under which $175.0 million in aggregate principal amount of notes of the same series were previously issued.

On May 21, 2005, we redeemed $65.0 million of our 10.125% Senior Notes pursuant to a redemption notice dated April 21, 2005 at the redemption price of 105.0625 percent. The redemption was funded by the net proceeds from the issuance of the $50.0 million additional 9.625% Senior Notes on April 21, 2005 and cash on hand.

On July 16, 2005, we redeemed $30.0 million of our 10.125% Senior Notes pursuant to a redemption notice dated July 16, 2005 at the redemption price of 105.0625 percent. The redemption was funded with net proceeds from the sale of our Latin America rigs and cash on hand.

On December 30, 2005, we redeemed in full the outstanding $35.6 million face value of our 10.125% Senior Notes pursuant to a redemption notice dated November 30, 2005 at the redemption price of 103.375 percent. The redemption was funded with cash on hand.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (continued)

We had total long-term debt of $353.7 million, excluding $20.0 million currently drawn on our revolving credit facility as of December 31, 2007. The long-term debt included:

	•		$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; and

	•		$225.0 million aggregate principal amount of 9.625 percent Senior Notes, which are due October 1, 2013 plus an associated $3.7 million in unamortized debt premium.

As of December 31, 2007, we had approximately $87.2 million of liquidity. This liquidity was comprised of $60.1 million of cash and cash equivalents on hand and $27.1 million of availability under the revolving credit facility. We do not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements nor guarantees of third-party financial obligations. We have no energy or commodity contracts.

The following table summarizes our future contractual cash obligations as of December 31, 2007:


			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)	$	350,000	$	—	$	—	$	125,000	$	225,000
Long-term debt — interest (1)		136,588		24,313		48,625		47,408		16,242
Operating leases (2)		8,502		4,450		3,133		919		—
Purchase commitments (3)		14,720		14,720		—		—		—

Total contractual obligations	$	509,810	$	43,483	$	51,758	$	173,327	$	241,242


Commercial commitments:
Long-term debt — revolving credit facility (4)	$	20,000	$	20,000	$	—	$	—	$	—
Standby letters of credit (4)		12,941		12,941		—		—		—

Total commercial commitments	$	32,941	$	32,941	$	—	$	—	$	—


(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 $3.7 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, 2007, related to rig upgrade projects and new rig construction.

(4)		We have a $60.0 million revolving credit facility. As of December 31, 2007, $20.0 million has been drawn down and $12.9 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $27.1 million of availability. The revolving credit facility expires September 20, 2012.

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 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.

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

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.

Impairment of Goodwill. We periodically assess whether the excess of cost over net assets acquired (goodwill) is impaired based generally on the estimated future cash flows 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 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 2005, 2006 and 2007 indicated that the fair value of operations to which goodwill relates exceeded the carrying values as of December 31, 2005, 2006 and 2007; accordingly, no impairments were recorded.

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.

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

Accounting for Income Taxes. We are a U.S. company and we operate through our various foreign branches and subsidiaries in numerous countries throughout the world. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be reflected on our income tax returns for the current year, nonresident withholding taxes or changes in prior year tax estimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported on the consolidated balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.

Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to the expiration of our NOL carryforwards. In the event that our earnings performance projections do not indicate that we will be able to benefit from our NOL carryforwards, valuation allowances are established. We periodically evaluate our ability to utilize our NOL carryforwards and, in accordance with 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.

Accounting for Derivative Instruments. We follow SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS 133 established accounting and disclosure requirements for most derivative instruments and hedge transactions involving derivatives. SFAS 133 also requires formal documentation procedures for hedging relationships and effectiveness testing when hedge accounting is to be applied.

In 2004, we entered into two variable-to-fixed interest rate swap agreements to reduce our cash flow exposure to increases in interest rates on our Senior Floating Rate Notes. The Senior Floating Rate Notes were redeemed in full on September 27, 2007. Both swap agreements were terminated or expired prior to redemption.

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

We did not use hedge accounting treatment for these interest rate swap agreements as we determined that the hedges would not be highly effective as defined by SFAS 133. The ineffectiveness of the hedges was caused by embedded written call options in the interest rate swap agreements that did not exist in the notes. Accordingly, we recognized the volatility of the swap agreements on a mark-to-market basis in our consolidated statement of operations. For the year ended December 31, 2007, we recognized a $0.7 million decrease in the fair value of the interest rate derivatives. For the year ended December 31, 2006, there was no significant change in the fair value of the interest rate derivatives. These non-cash items are reported in the consolidated statement of operations as “Changes in fair value of 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. For additional information see Note 6 in the notes to the consolidated financial statements.

Recent Accounting Pronouncements

See Note 17 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 $239.1 million at December 31, 2007. The estimated fair value of our $125.0 million principal amount of Convertible Senior Notes due 2012 was $113.6 million on December 31, 2007.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Parker Drilling Company:

We have audited the accompanying consolidated balance sheet of Parker Drilling Company and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2007. We also have audited Parker Drilling Company’s internal control over financial reporting as of December 31, 2007, 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 Parker Drilling Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 as of December 31, 2007, and the results of its operations and its cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Parker Drilling Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (continued)

As discussed in notes 1 and 7 to the consolidated financial statements, the Company changed its method of accounting for uncertain tax positions as of January 1, 2007.

/s/ KPMG LLP

Houston, Texas
February 26, 2008

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of
Parker Drilling Company:

In our opinion, the consolidated balance sheet as of December 31, 2006 and the related consolidated statements of operations, stockholder’s equity and cash flows for each of two years in the period ended December 31, 2006 present fairly, in all material respects, the financial position of Parker Drilling Company and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period 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 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 audits provide a reasonable basis for our opinion.

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,
	2007			2006			2005
Drilling and rental revenues:
U.S. drilling	$	231,139		$	191,225		$	128,252
International drilling		285,403			273,216			308,572
Rental tools		138,031			121,994			94,838

Total drilling and rental revenues		654,573			586,435			531,662


Drilling and rental operating expenses:
U.S. drilling		98,393			83,462			66,827
International drilling		215,279			219,710			237,161
Rental tools		54,377			46,454			38,211
Depreciation and amortization		85,803			69,270			67,204

Total drilling and rental operating expenses		453,852			418,896			409,403


Drilling and rental operating income		200,721			167,539			122,259









General and administration expense		(24,708	)		(31,786	)		(27,830	)
Provision for reduction in carrying value of certain assets		(1,462	)		—			(4,884	)
Gain on disposition of assets, net		16,432			7,573			25,578

Total operating income		190,983			143,326			115,123


Other income and (expense):
Interest expense		(25,157	)		(31,598	)		(42,113	)
Change in fair value of derivative positions		(671	)		40			2,076
Interest income		6,478			7,963			2,241
Loss on extinguishment of debt		(2,396	)		(1,912	)		(8,241	)
Equity in loss of unconsolidated joint venture and related charges		(27,101	)		—			—
Minority interest		(1,000	)		(229	)		1,905
Other		665			(155	)		(763	)

Total other income and (expense)		(49,182	)		(25,891	)		(44,895	)

Income before income taxes		141,801			117,435			70,228


Income tax expense (benefit):
Current tax expense		17,602			20,654			16,328
Deferred tax expense (benefit)		20,121			15,755			(44,912	)

Total income tax expense (benefit)		37,723			36,409			(28,584	)


Income from continuing operations		104,078			81,026			98,812

Discontinued operations		—			—			71

Net income	$	104,078		$	81,026		$	98,883


Basic earnings per share:
Income from continuing operations	$	0.95		$	0.76		$	1.03
Discontinued operations	$	—		$	—		$	—
Net income	$	0.95		$	0.76		$	1.03

Diluted earnings per share:
Income from continuing operations	$	0.94		$	0.75		$	1.02
Discontinued operations	$	—		$	—		$	—
Net income	$	0.94		$	0.75		$	1.02

Number of common shares used in computing earnings per share:
Basic		109,542,364			106,552,015			95,818,893
Diluted		110,856,694			108,138,384			97,208,345

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,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	104,078		$	81,026		$	98,883
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		85,803			69,270			67,204
Amortization of debt issuance and premium		845			764			958
Loss on extinguishment of debt		1,396			910			935
Gain on disposition of assets		(16,432	)		(7,573	)		(25,549	)
Provision for reduction in carrying value of certain assets		1,462			—			4,884
Deferred tax expense (benefit)		20,121			15,755			(44,912	)
Equity loss in unconsolidated joint venture		27,101			—			—
Expenses not requiring cash		10,597			9,674			2,913
Change in assets and liabilities:
Accounts and notes receivable		(60,209	)		(3,456	)		(568	)
Rig materials and supplies		(4,945	)		(2,605	)		(3,179	)
Other current assets		(12,720	)		34,420			7,589
Accounts payable and accrued liabilities		(19,728	)		(28,143	)		18,218
Accrued income taxes		(48,998	)		(3,101	)		(5,100	)
Other assets		(14,095	)		(73	)		331

Net cash provided by operating activities		74,276			166,868			122,607


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(242,098	)		(195,022	)		(69,492	)
Proceeds from the sale of assets		23,445			50,790			61,046
Proceeds from insurance claims		7,844			4,501			13,850
Investment in unconsolidated joint venture		(5,000	)		(10,000	)		—
Purchase of marketable securities		(101,075	)		(198,120	)		(18,000	)
Proceeds from sale of marketable securities		163,995			153,200			—

Net cash used in investing activities		(152,889	)		(194,651	)		(12,596	)

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,
	2007			2006			2005
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	$	125,000		$	—		$	55,500
Principal payments under debt obligations		(100,000	)		(50,000	)		(155,632	)
Proceeds from draw on revolver credit facility		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		(4,618	)		—			(655	)
Proceeds from stock options exercised		15,455			7,537			6,685
Excess tax benefit from stock-based compensation		1,922			2,326			—

Net cash provided by (used in) financing activities		46,534			59,810			(94,102	)


Net increase (decrease) in cash and cash equivalents		(32,079	)		32,027			15,909

Cash and cash equivalents at beginning of year		92,203			60,176			44,267

Cash and cash equivalents at end of year	$	60,124		$	92,203		$	60,176


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	27,439		$	30,898		$	41,308
Income taxes	$	74,801		$	21,566		$	13,415

Discontinued operations:
Depreciation	$	—		$	—		$	—
Loss on disposition of assets	$	—		$	—		$	29
Provision for reduction in carrying value of certain assets	$	—		$	—		$	—

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, 2004		94,999	$	15,833	$	441,085		$	(718	)	$	—	$	(307,283	)

Activity in employees’ stock plans		2,837		473		13,495			(6,217	)		—		—
Income tax benefit from stock options exercised		—		—		1,555			—			—		—
Amortization of restricted stock plan compensation		—		—		—			2,723			—		—
Net income (total comprehensive income of $98,883)		—		—		—			—			—		98,883

Balances, December 31, 2005		97,836		16,306		456,135			(4,212	)		—		(208,400	)

Adoption of FAS123R		—		—		(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			—			—		—
Sale of warrants on Senior Convertible Notes		—		—		20,250			—			—		—
Purchase of call options on Senior Convertible Notes		—		—		(31,475	)		—			—		—
OID premium deferred tax asset on call options of Senior Convertible Notes		—		—		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	)

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 and another in which a subsidiary has 80 percent stock ownership but exert control over both of the entities’ operations (collectively, the “Company”). A subsidiary of Parker Drilling also has a 50 percent interest in two other companies (one of which is our joint venture in Saudi Arabia which is more fully described in Note 8), both of which are accounted for under the equity method as the Company’s interest in the entities 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, 2007, the Company’s marketable rig fleet consists of 18 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 range of ancillary services, including engineering, logistics and project management activities.

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.

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 $25.4 million, $35.9 million and $41.3 million during the years ended December 31, 2007, 2006 and 2005, 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.

Marketable Securities — The Company had no investment in marketable securities as of December 31, 2007 and $62.9 million as of December 31, 2006, which consisted of variable rate auction securities classified as available for sale. The investments were carried at par value and were sold in September 2007.

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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


	December 31,
	2007			2006
	(Dollars in Thousands)
Trade	$	169,811		$	113,819
Employee (1)		47			21
Allowance for doubtful accounts (2)		(3,152	)		(1,481	)

Total receivables	$	166,706		$	112,359


(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, 2007, 2006 and 2005 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 2007 and 2006 related to the construction of rigs totaled $6.2 million and $3.6 million, respectively. No interest was capitalized in 2005.

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, net of a reserve for obsolete parts of $2.6 million and $4.3 million at December 31, 2007 and 2006, respectively.

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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.

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, 2007 and 2006, the Company had deposits in domestic banks in excess of federally insured limits of approximately $48.2 million and $79.2 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2007 and 2006 of $18.9 million and $18.2 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 2007, ExxonMobil accounted for approximately 11 percent of total revenues.

Derivative Financial Instruments — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137, 138 and 149 require that every derivative instrument be recorded on the balance sheet as either an asset or liability measured by its fair value. The Company has used derivative instruments to hedge exposure to interest rate risk. For hedges which meet the criteria of SFAS No. 133, the Company formally designates and documents the instrument as a hedge of a specific underlying exposure, as well as the risk management objective and strategy for undertaking each hedge transaction. For those derivative instruments that do not meet the criteria of a hedge, the Company recognizes the volatility of the derivative instruments on a mark-to-market basis in the consolidated statement of operations. See Note 6.

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 $239.1 million at December 31, 2007. The estimated fair value of the Company’s $125.0 million principal amount of Convertible Senior Notes due 2012 was $113.6 million on December 31, 2007. See Note 4.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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. The following table illustrates the effect on net income and net income per share as if we had applied the fair value based provisions of SFAS 123R for the period ended December 31, 2005.


	Year Ended
	December 31, 2005
	(Dollars in Thousands)

Net income (loss) as reported	$	98,883

Stock-based compensation expense included in net income (loss) as reported		1,704

Stock-based compensation expense determined under fair value method		(1,855	)

Net income (loss) pro forma	$	98,732


Basic earnings (loss) per share:
Net income (loss) as reported	$	1.03
Net income (loss) pro forma	$	1.03

Diluted earnings (loss) per share:
Net income (loss) as reported	$	1.02
Net income (loss) pro forma	$	1.02

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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 each option is estimated on the date of grant. There were no option grants in 2007. The following is a summary of valuation assumptions for grants during the years ended December 31, 2006 and 2005:


	2006 (1)		2005
Expected price volatility		16.90%		51.1%
Risk-free interest rate range		4.23%		3.38%
Expected life of stock options	3 months		3-7 years


(1)		The stock option grant during the first quarter of 2006 was a discounted option that was made to provide the recipient with the same value as a grant which he had been advised that he would receive in 1999 but was not awarded at that time due to an oversight. The option was vested at the grant date and had an April 14, 2006 expiration date. Accordingly, the volatility and expected term assumptions in 2006 are not comparable with those calculated for 2005.

There were no options granted in 2007 or 2006 under the 1997 Stock Plan. Options granted in 2005 under the 1997 Stock Plan had an estimated fair value of $50 thousand. 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 $1.9 million for the year ended December 31, 2007 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, 2007 was $15.5 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

Discontinued Operations — Pursuant to a board approved plan to sell certain U.S. Gulf of Mexico offshore assets in 2003, the Company included these assets and related spare parts and inventories as discontinued operations beginning in 2003. The sale of all but one of the U.S. Gulf of Mexico offshore rigs that remained in discontinued operations was completed in August 2004. Jackup Rig 25, the final rig approved for sale pursuant to the Board’s 2003 plan, was sold on January 3, 2005. The Company received proceeds of $21.5 million. The rig had been impaired prior to 2005 and no additional gain or loss was recognized due to the sale. With the completion of this transaction all the jackup and platform rigs have been sold from the U.S. Gulf of Mexico asset group. No other assets remain related to the Company’s discontinued operations.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 — Disposition of Assets (continued)

The following table presents the results of operations related to discontinued operations:


	Year Ended December 31,
	2007		2006		2005
	(Dollars in Thousands)
U.S. jackup and platform drilling revenues	$	—	$	—	$	193


U.S. jackup and platform drilling gross margin	$	—	$	—	$	100
Depreciation and amortization		—		—		—
Loss on disposition of assets, net of gains and impairment		—		—		(29	)

Income from discontinued operations	$	—	$	—	$	71

Disposition of Assets — 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). On May 6, 2005 the Company entered into definitive agreements with affiliates of Saxon Energy Services, Inc. (“Saxon”) to sell its seven remaining land rigs and related assets in Colombia and Peru for a total purchase price of $34.0 million. The Company closed on the sale of four of the rigs and related assets in the second quarter and the remaining three rigs were sold in the third quarter. As a result of the sale of all seven land rigs, a gain of $13.8 million was recognized in 2005.

Involuntary Conversion of Assets — On June 24, 2005, a well control incident occurred on Rig 255 while operating under contract in Bangladesh, resulting in the total loss of the drilling unit. As the rig was immediately rendered a total loss by our insurer in early July, the Company wrote off the net book value of the rig of $5.6 million and recorded insurance proceeds of $13.8 million, the insured value of assets destroyed, resulting in a gain of $8.2 million in the second quarter of 2005. Another $2.3 million gain was recognized in the fourth quarter of 2005. As we received partial settlement from our insurance accident site cleanup and settled on rig materials and supplies that were not destroyed in the incident, we recorded another $1.4 million gain in 2006 relating to the sale of the rig’s salvageable assets. The Company received $7.5 million of the insurance proceeds in the third quarter of 2005 and the remaining proceeds were received in the fourth quarter 2005.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 — Disposition of Assets (continued)

Provision for Reduction in Carrying Value of an Asset — In 2007, the Company recognized $1.5 million in provision for reduction in carrying value related to disputed accounts receivable. In the third quarter of 2005, the Company recognized $2.3 million in provision for reduction in carrying value of an insurance asset representing the premiums paid on a life insurance policy for Robert L. Parker, who was chairman of the board and director of the Company, in anticipation of a settlement of its obligation under this arrangement. See Note 14. In addition, Barge Rig 57 was damaged in July 2005 in a towing incident resulting in a $2.6 million impairment. Subsequently, during the third quarter of 2006, we settled with the insurance carrier and recorded a gain of $1.9 million relating to this rig. On November 8, 2005, a well control incident on Rig 247 occurred while operating under contract in Turkmenistan. Rig equipment has been assessed for repair or replacement. The Company recorded a $1.2 million estimated impairment to the rig and a $1.2 million insurance receivable in December 2005.

Assets Held for Sale — The assets held for sale of $4.8 million as of December 31, 2006 was comprised of the net book value of two workover barge rigs and related inventory that were subsequently sold on January 2, 2007 for a sales price of $20.5 million, resulting in a gain of $15.1 million which was reported in the first quarter of 2007.

Note 3 — Goodwill

As of December 31, 2007 and 2006, the goodwill by reporting unit was: U.S. drilling barge rigs — $64.2 million and rental tools — $36.1 million.

Note 4 — Long-Term Debt


	December 31,
	2007		2006
	(Dollars in Thousands)
Senior Floating Rate Notes payable in September 2010 with interest at three-month LIBOR + 4.75% payable quarterly in March, June, September and December (effective interest rate of 10.12% at December 31, 2006.)	$	—	$	100,000

Convertible Senior Notes payable in July 2012 with interest at 2.125% payable semi-annually in January and July.		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 $3,721 at December 31, 2007 and $4,368 at December 31, 2006 (effective interest rate of 9.24% at December 31, 2007 and 9.27% at December 31, 2006)		228,721		229,368

Revolving Credit Facility with interest at prime plus an applicable margin or LIBOR plus an applicable margin (interest rate of 8.75% at December 31, 2007)		20,000		—


Total debt		373,721		329,368
Less current portion		20,000		—

Total long-term debt	$	353,721	$	329,368

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 — Long-Term Debt (continued)

The aggregate maturities of long-term debt for the five years ending December 31, 2012 are as follows: $20.0 million for 2008-2010, $125.0 million for 2012 and $225.0 million thereafter.

Activity in 2007 — On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125 percent Convertible Senior Notes due July 15, 2012. Interest is payable semiannually on July 15th and January 15th. The initial conversion price is approximately $13.85 per share and is subject to adjustment for the occurrence of certain events stated within the indenture. Proceeds from the transaction were used to redeem our outstanding Senior Floating Rate notes, to pay the net cost of the hedge and warrant transactions described below, and for general corporate purposes.

In connection with the offering of the Convertible Senior Notes, the Company also entered into separate convertible note hedge transactions (collectively, the “convertible hedge transactions”) with respect to its common stock with each of Bank of America, N.A., Deutsche Bank AG, London Branch and Lehman Brothers OTC Derivatives Inc. (collectively, the “Hedge Participants”). The convertible hedge transactions cover, subject to customary anti-dilution adjustments, approximately 9.0 million shares of our common stock. Separately and concurrently with entering into the convertible hedge transactions, the Company also entered into warrant transactions (collectively, the “warrant transactions”) with the Hedge Participants whereby the Company sold to the Hedge Participants warrants to acquire, subject to customary anti-dilution adjustments, up to approximately 9.0 million shares of its common stock. The convertible hedge and issuer warrant transactions are separate transactions entered into by the Company with the Hedge Participants, are not part of the terms of the Convertible Senior Notes and will not affect the holders’ rights under the Convertible Senior Notes. Holders of the Convertible Senior Notes will not have any rights with respect to the convertible hedge and warrant transactions. Effectively, the hedge and warrant transactions increase the conversion price to approximately $18.29 per share.

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.

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 is reflected in current portion of long-term debt in our 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. 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.

Activity in 2005 — On February 7, 2005, the Company redeemed $25.0 million face value of its 10.125% Senior Notes pursuant to a redemption notice dated January 6, 2005 at the redemption price of 105.0625 %. An expense of $1.4 million was recognized as loss on extinguishment of debt.

On April 21, 2005, the Company issued an additional $50.0 million in aggregate principal amount of its 9.625% Senior Notes due 2013 at a premium. The offering price of 111 percent of the principal amount resulted in gross proceeds of $55.5 million. The $5.5 million premium is reflected as long-term debt and amortized over the term of the notes. The additional notes were issued under an indenture, dated as of October 10, 2003, under which $175.0 million in aggregate principal amount of notes of the same series were previously issued.

On May 21, 2005, the Company redeemed $65.0 million of its 10.125% Senior Notes pursuant to a redemtion notice dated June 16, 2005 at the redemption price of 105.0625%. The redemption was funded with net proceeds from the $50.0 million additional 9.625% Senior Notes on April 21, 2005. An expense of $3.3 million was recognized as loss on extinguishment of debt.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 — Long-Term Debt (continued)

On July 16, 2005, the Company redeemed $30.0 million of its 10.125% Senior Notes pursuant to a redemption notice dated June 16, 2005 at the redemption price of 105.0625%. The redemption was funded with net proceeds from the sale of our Latin America rigs and cash on hand. An expense of $1.9 million was recognized as loss on extinguishment of debt.

On December 30, 2005, the Company redeemed in full the outstanding $35.6 million face value of its 10.125% Senior Notes pursuant to a redemption notice dated November 30, 2005 at the redemption price of 103.375%. The redemption was funded with cash on hand. An expense of $1.6 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 (a Kazakhstan closed joint stock company, owned 80 percent by Parker Drilling (Kazakstan), Ltd. and 20 percent by Aralnedra, CJSC), 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., Parker TNK Drilling, 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 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, 2007 and December 31, 2006 and for the years ended December 31, 2007, 2006 and 2005. 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)


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

Drilling and rental revenues	$	—		$	573,164		$	136,319		$	(54,910	)	$	654,573

Drilling and rental operating expenses		1			311,867			111,091			(54,910	)		368,049
Depreciation and amortization		—			77,204			8,599			—			85,803

Drilling and rental operating income (loss)		(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 and related charges		—			—			(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)


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

Drilling and rental revenues	$	3		$	510,157		$	123,506		$	(47,231	)	$	586,435

Drilling and rental operating expenses		—			274,862			121,995			(47,231	)		349,626
Depreciation and amortization		—			65,221			4,049			—			69,270

Drilling and rental operating income		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 STATEMENT OF OPERATIONS
(Dollars in Thousands)


	Year Ended December 31, 2005
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Drilling and rental revenues	$	—		$	403,024		$	156,802		$	(28,164	)	$	531,662

Drilling and rental operating expenses		1			218,189			152,173			(28,164	)		342,199
Depreciation and amortization		—			63,226			3,978			—			67,204

Drilling and rental operating income (loss)		(1	)		121,609			651			—			122,259


General and administrative expense(1)		(179	)		(27,632	)		(19	)		—			(27,830	)
Provision for reduction in carrying value of certain assets		(2,300	)		(2,584	)		—			—			(4,884	)
Gain on disposition of assets, net		38			24,590			950			—			25,578

Total operating income (loss)		(2,442	)		115,983			1,582			—			115,123


Other income and (expense):
Interest expense		(46,856	)		(48,880	)		(2,664	)		56,287			(42,113	)
Changes in fair value of derivative positions		2,076			—			—			—			2,076
Interest income		46,565			8,641			3,322			(56,287	)		2,241
Loss on extinguishment of debt		(8,241	)		—			—			—			(8,241	)
Minority interest		—			—			1,905			—			1,905
Other		(655	)		(147	)		39			—			(763	)
Equity in net earnings of subsidiaries		109,271			—			—			(109,271	)		—

Total other income and (expense)		102,160			(40,386	)		2,602			(109,271	)		(44,895	)

Income (loss) before income taxes		99,718			75,597			4,184			(109,271	)		70,228

Income tax expense (benefit):
Current tax expense		2,672			11,358			2,298			—			16,328
Deferred tax benefit		(1,837	)		(44,678	)		1,603			—			(44,912	)

Income tax expense (benefit)		835			(33,320	)		3,901			—			(28,584	)

Income (loss) from continuing operations		98,883			108,917			283			(109,271	)		98,812

Discontinued operations		—			71			—			—			71

Net income (loss)	$	98,883		$	108,988		$	283		$	(109,271	)	$	98,883


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

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
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 BALANCE SHEET
(Dollars in Thousands)


	December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	60,029		$	14,367		$	17,807		$	—		$	92,203
Marketable securities		60,920			2,000			—			—			62,920
Accounts and notes receivable, net		53,844			143,905			33,625			(119,015	)		112,359
Rig materials and supplies		—			7,173			7,827			—			15,000
Deferred costs		—			6,321			341			—			6,662
Other current assets		18,105			8,969			1,319			37			28,430

Total current assets		192,898			182,735			60,919			(118,978	)		317,574


Property, plant and equipment, net		134			354,356			80,861			122			435,473

Assets held for sale		—			4,828			—			—			4,828

Goodwill		—			100,315			—			—			100,315

Investment in subsidiaries and intercompany advances		694,050			846,800			(8,053	)		(1,532,797	)		—

Other noncurrent assets		18,043			19,774			5,294			—			43,111

Total assets	$	905,125		$	1,508,808		$	139,021		$	(1,651,653	)	$	901,301

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	44,667		$	175,092		$	44,611		$	(169,144	)	$	95,226
Accrued income taxes		(10,514	)		17,039			152			—			6,677

Total current liabilities		34,153			192,131			44,763			(169,144	)		101,903


Long-term debt		329,368			—			—			—			329,368
Other long-term liabilities		1,596			9,030			265			40			10,931
Intercompany payables		80,909			544,250			37,219			(662,378	)		—

Commitments and contingences (Note 13)		—			—			—			—			—
Stockholders’ equity:
Common stock		18,220			39,899			21,251			(61,150	)		18,220
Capital in excess of par value		568,253			1,013,736			34,526			(1,048,262	)		568,253
Retained earnings (accumulated deficit)		(127,374	)		(290,238	)		997			289,241			(127,374	)

Total stockholders’ equity		459,099			763,397			56,774			(820,171	)		459,099

Total liabilities and stockholders’ equity	$	905,125		$	1,508,808		$	139,021		$	(1,651,653	)	$	901,301

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 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

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


	Year Ended December 31, 2005
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	98,883		$	108,988		$	283		$	(109,271	)	$	98,883
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		—			63,226			3,978			—			67,204
Amortization of debt issuance and premium		958			—			—			—			958
Loss on extinguishment of debt		935			—			—			—			935
Gain on disposition of assets		(38	)		(24,561	)		(950	)		—			(25,549	)
Provision for reduction in carrying value of certain assets		2,300			2,584			—			—			4,884
Deferred tax expense (benefit)		(1,837	)		(44,678	)		1,603			—			(44,912	)
Expenses not requiring cash		1,713			1,200			—			—			2,913
Equity in net earnings of subsidiaries		(109,271	)		—			—			109,271			—
Change in operating assets and liabilities		139,247			(131,278	)		9,322			—			17,291

Net cash provided by (used in) operating activities		132,890			(24,519	)		14,236			—			122,607


Cash flows from investing activities:
Capital expenditures		—			(63,806	)		(5,686	)		—			(69,492	)
Proceeds from the sale of assets		38			57,184			3,824			—			61,046
Proceeds from insurance claims		—			13,850			—			—			13,850
Purchase of marketable securities		(16,000	)		(2,000	)		—			—			(18,000	)

Net cash provided by (used in) investing activities		(15,962	)		5,228			(1,862	)		—			(12,596	)


Cash flows from financing activities:
Proceeds from issuance of debt		55,500			—			—			—			55,500
Principal payments under debt obligations		(155,632	)		—			—			—			(155,632	)
Payment of debt issuance costs		(655	)		—			—			—			(655	)
Proceeds from stock options exercised		6,685			—			—			—			6,685
Intercompany advances, net		(7,525	)		22,498			(14,973	)		—			—

Net cash provided by (used in) financing activities		(101,627	)		22,498			(14,973	)		—			(94,102	)


Net increase (decrease) in cash and cash equivalents		15,301			3,207			(2,599	)		—			15,909

Cash and cash equivalents at beginning of year		16,677			7,938			19,652			—			44,267

Cash and cash equivalents at end of year	$	31,978		$	11,145		$	17,053		$	—		$	60,176

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 before income taxes and discontinued operations is summarized below:


	Year Ended December 31,
	2007		2006		2005
	(Dollars in Thousands)
United States	$	127,484	$	99,024	$	23,021
Foreign		14,317		18,411		47,207

	$	141,801	$	117,435	$	70,228

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 — Income Taxes (continued)

Income tax expense (benefit) related to continuing operations are summarized as follows:


	Year Ended December 31,
	2007			2006			2005
	(Dollars in Thousands)
Current:
United States:
Federal	$	13,860		$	13,046		$	1,837
State		791			—			18
Foreign		2,951			7,608			14,473
Deferred:
United States:
Federal		16,559			30,436			(46,537	)
State		4,290			(12,617	)		—
Foreign		(728	)		(2,064	)		1,625

	$	37,723		$	36,409		$	(28,584	)

Total income tax expense differs from the amount computed by multiplying income (loss) before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows:


	Year Ended December 31,
	2007						2006						2005
				% of						% of						% of
				Pre-Tax						Pre-Tax						Pre-Tax
	Amount			Income			Amount			Income			Amount			Income
	(Dollars in Thousands)
Computed expected tax expense	$	49,630			35	%	$	41,104			35	%	$	24,580			35	%
Foreign taxes, (net of federal benefit-pre-07)		12,669			9	%		5,820			5	%		7,496			11	%
State taxes, net of federal benefit		5,080			4	%		—			—			—			—
Foreign tax credits		(16,020	)		(11	)%		—			—			—			—
Kazakhstan tax credits		(22,547	)		(16	)%		—			—			—			—
Other Kazakhstan FIN 48 items		(12,427	)		(9	)%
Change in valuation allowance		5,764			4	%		—			—			(71,497	)		(102	)%
Foreign corporation income		8,916			6	%		1,524			2	%		9,055			13	%
FIN 48		7,807			5	%		—			—			—			—
Benefit of State NOL		—			—			(12,617	)		(11	)%		—			—
Permanent differences		(161	)		—			1,404			1	%		1,740			2	%
Other		(988	)		—			(826	)		(1	)%		42			—

Actual tax expense	$	37,723			27	%	$	36,409			31	%	$	(28,584	)		(41	)%

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 — Income Taxes (continued)

The components of the Company’s deferred tax assets and (liabilities) as of December 31, 2007 and 2006 are shown below:


	December 31,
	2007			2006
	(Dollars in Thousands)
Deferred tax assets
Current deferred tax assets:
Reserves established against realization of certain assets	$	6,563		$	4,375
Accruals not currently deductible for tax purposes		2,860			12,932

Gross current deferred tax assets		9,423			17,307
Valuation allowance		0			0

Net current deferred tax assets		9,423			17,307

Non-current deferred tax assets:
State net operating loss carryforwards		9,217			12,617
Foreign tax credits		6,300			0
Other long term liabilities		2,149			2,149
Deferred stock based compensation		370			3,693
Unamortized OID benefit		11,239			0
Indirect FIN 48 U.S. tax benefit		13,381			0

Gross long-term deferred tax assets		42,656			18,459
Valuation allowance		(6,391	)		0

Net non-current deferred tax assets		36,265			18,459

Net deferred tax assets		45,688			35,766

Deferred tax liabilities:
Non-current deferred tax liabilities:
Property, plant and equipment		8,571			10,940
Goodwill		(14,336	)		(14,561	)
Other		1,577			(1,433	)

Net non-current deferred tax liabilities		(4,188	)		(5,054	)

Net deferred tax asset	$	41,500		$	30,712

As part of the process of preparing the consolidated financial statements, the Company is required to determine its income taxes. This process involves estimating the annual effective tax rate and the nature and measurements of temporary differences resulting from differing treatment of items for tax and accounting purposes. These differences, and the NOL carryforwards, result in deferred tax assets and liabilities. In each period, the Company assesses the likelihood that its deferred tax assets will be recovered from existing deferred tax liabilities or future taxable income in each 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 — Income Taxes (continued)

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. At December 31, 2007, the Company had $6.3 million of foreign tax credit carryforwards and had $119.9 million of gross state NOL carryforwards. For tax purposes, the foreign tax credit carryforwards expire over a 10 year period ending 2017 and the state NOL carryforwards expire over a 16 year period ending December 31, 2014 through 2023.

The 2006 and 2005 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 NOL’s was no longer required. The $29.5 million decrease in the NOL carryforward component of deferred tax assets in 2005 is primarily due to utilization of NOL carryforwards in the Company’s 2005 federal income tax return that was filed in 2006. The $56.0 million decrease in the valuation allowance component in 2005 was primarily due to expected utilization of gross NOL carryforwards. The $34 .8 million decrease in the NOL carryforward component of deferred tax assets in 2006 is primarily due to the projected full utilization of NOL carryforwards in the Company’s 2006 federal income tax return filed in 2007.

The Company also had a deferred tax asset related to state NOL’s which was recorded in the second quarter of 2006 with a full valuation. These state deferred tax assets relate primarily to prior years operating losses. GAAP required the Company to recognize a valuation allowance unless it was “more likely than not” that the Company could realize the benefit of the state NOL carryforwards. During the year ended December 31, 2006, the Company utilized $5.4 million related to state taxable income to be reported in its 2006 state tax return. In addition, during the fourth quarter 2006, the Company determined that it was “more likely than not” that a valuation allowance was no longer needed, therefore the Company reflected a net state NOL benefit of $12.6 million. At December 31, 2006, the Company had $168 million of gross state NOL carryforwards. For tax purposes, the state NOL carryforwards expire over a 15 year period ending December 31, 2015 through 2019.

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 1,2007	$	(49.3	)
Additions based on tax positions taken during a prior period		—
Reductions based on tax positions taken during a prior period		3.8
Additions based on tax positions taken during the current period		(4.6	)
Reductions based on tax positions taken during the current period		—
Reductions related to settlement of tax matters		36.3
Reductions related to a lapse of applicable statute of limitations		0.7

Balance at December 31, 2007	$	(13.1	)

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, 2007:


United States — Federal		1985-present
Bolivia		2000-present
Kazakhstan		2002-present
Mexico		2002-present
Papua New Guinea		2001-present
Russia		2005-present
New Zealand		2002-present
Colombia		2005-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, 2007, the company had a liability for unrecognized tax benefits of $13.1 million (of which $11.0 million, 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 January 1, 2007 and December 31, 2007 we had approximately $52.5 million and $40.3 million of accrued interest and penalties related to uncertain tax positions, respectively. The Company recognized $5.7 million of interest and a $17.9 million reduction related to penalties on unrecognized tax benefits for the year ended December 31, 2007.

Note 8 — Saudi Arabia Joint Venture

A subsidiary of Parker Drilling Company is a 50 percent shareholder of Al-Rushaid Parker Drilling, a Saudi Arabia limited liability company (“ARPD”), which has a six rig drilling contract with Saudi Aramco (“SA Contract”). ARPD has obtained bank financing for $160 million of the cost of the six rigs, which loan is secured by assignment of proceeds of the SA Contract and the personal guarantee of the Chairman of Abdullah Rasheed Al-Rushaid Company for Drilling Oil and Gas Limited, our Saudi partner (“AR”). Our subsidiary and AR have each currently advanced $20.0 million in shareholder loans to fund construction costs for the rigs. Although the joint venture can provide no assurance as to the final cost, due to construction delays and cost overruns, including remedial work to correct problems with construction, integration of components and rig specifications, the costs to complete construction of the rigs is anticipated to be approximately $30.0 to $40.0 million over the next three to four months.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Saudi Arabia Joint Venture (continued)

The first four rigs began drilling operations on April 21, 2007, July 17, 2007, October 8, 2007 and December 22, 2007, respectively. Due to the delays in commencement of operations under the rig contracts, Parker’s subsidiary has accrued $13.8 million (50 percent of ARPD exposure) for potential liquidated damages attributable to all six rigs through June 2008. ARPD’s customer, Saudi Aramco, initially suspended deducting liquidated damages for six months, but began deducting liquidated damages in November of 2007 by withholding 50% of the ARPD invoices for November and December 2007. At the request of ARPD, Saudi Aramco has subsequently re-instituted its suspension of any further deductions for liquidated damages pending resolution of this matter.

Parker Drilling’s subsidiary also 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 has also 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.

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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
1994 Non-Employee Director Incentive Plan
Non-qualified	$	3.280			4,000	1.01 years		$	3.280	$	17,080
Non-qualified	$	12.090			10,000	0.01 years		$	12.090	$	—

1994 Executive Stock Option Plan
Incentive option	$	8.875			—			$	—	$	—
Non-qualified	$	8.875			—			$	—	$	—

1997 Stock Plan
Incentive option	$	10.813			46,240	0.23 years		$	10.813	$	—
Non-qualified	$	1.990	- $	5.350	917,800	1.31 years		$	3.741	$	3,496,818
Non-qualified	$	10.810			3,760	0.23 years		$	10.810	$	—

2005 Long-Term Incentive Plan
Non-qualified	$	8.875			—			$	—	$	—


				Exercisable Options
						Weighted
						Average		Aggregate
				Number of		Exercise		Intrinsic
Plan	Exercise Prices			Shares		Price		Value
1994 Non-Employee Director Incentive Plan
Non-qualified	$	3.280			4,000	$	3.280	$	17,080
Non-qualified	$	8.875	- $12.090		10,000	$	12.090	$	—

1994 Executive Stock Option Plan
Incentive option	$	8.875			—	$	—	$	—
Non-qualified	$	8.875			—	$	—	$	—

1997 Stock Plan
Incentive option	$	10.813			46,240	$	10.813	$	—
Non-qualified	$	1.990	- $ 5.350		917,800	$	3.741	$	3,496,818
Non-qualified	$	10.810			3,760	$	10.810	$	—

2005 Long-Term Incentive Plan
Non-qualified	$	8.875			—	$	—	$	—

The Company had 1,143,360 and 838,875 shares held in Treasury stock at December 31, 2007 and 2006, respectively.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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


	December 31,
	2007		2006
Stock plans		2,118,089		5,372,934
Stock bonus plan		304,402		87,983

Total shares reserved for issuance		2,422,491		5,460,917

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 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 rights, which do not have voting privileges, expire June 30, 2008, and at the Company’s option, may be redeemed by the Company in whole, but not in part, prior to expiration for $0.01 per right. Until the rights become exercisable, they have no dilutive effect on earnings per share.

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, 2005
	Income (Loss)		Shares		Per-Share
	(Numerator)		(Denominator)		Amount
Basic EPS:
Income from continuing operations	$	98,812,000		95,818,893	$	1.03
Discontinued operations		71,000				—


Net income	$	98,883,000			$	1.03


Effect of dilutive securities:
Stock options and restricted stock				1,389,452	$	(0.01	)

Diluted EPS:
Income from continuing operations	$	98,812,000		97,208,345	$	1.02
Discontinued operations		71,000				—


Net income	$	98,883,000			$	1.02

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. For the year ended December 31, 2005, options to purchase 2,796,000 shares of common stock at prices ranging from $8.875 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on 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 283,581, 219,204 and 205,011 shares to the Plan in 2007, 2006 and 2005, respectively, with the Company recognizing expense of $2.5 million, $1.8 million and $1.4 million for each of the respective periods.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Business Segments

The Company is organized into three primary business segments: U.S. drilling operations, international drilling operations, and rental tools. This is the basis management uses for making operating decisions and assessing performance.


	Year Ended December 31,
Operations by Industry Segment	2007			2006			2005
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling (1)	$	231,139		$	191,225		$	128,252
International drilling (1)		285,403			273,216			308,572
Rental tools (1)		138,031			121,994			94,838

Total drilling and rental revenues		654,573			586,435			531,662

Drilling and rental operating income (loss):
U.S. drilling (2)		99,514			83,370			41,739
International drilling (2)		41,943			27,465			40,281
Rental tools (2)		59,264			56,704			40,239

Total drilling and rental operating income		200,721			167,539			122,259

General and administrative expense		(24,708	)		(31,786	)		(27,830	)
Provision for reduction in carrying value of certain assets		(1,462	)		—			(4,884	)
Gain on disposition of assets, net		16,432			7,573			25,578


Total operating income		190,983			143,326			115,123
Interest expense		(25,157	)		(31,598	)		(42,113	)
Changes in fair value of derivative positions		(671	)		40			2,076
Loss on extinguishment of debt		(2,396	)		(1,912	)		(8,241	)
Equity in loss of unconsolidated joint venture and related charges		(27,101	)		—			—
Minority interest		(1,000	)		(229	)		1,905
Other		7,143			7,808			1,478

Income from continuing operations before income taxes	$	141,801		$	117,435		$	70,228

Identifiable assets:
U.S. drilling	$	235,030		$	255,275
International drilling		441,282			318,767
Rental tools		177,033			166,270


Total identifiable assets		853,345			740,312

Corporate assets		223,642			160,989

Total assets	$	1,076,987		$	901,301


(1)		In 2007, ExxonMobil accounted for approximately 11 percent of the Company’s total revenues, approximately $63.0 million of the Company’s international drilling 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 international drilling segment revenues and approximately $19.0 million of the Company’s rental tools segment revenues. In 2005, ExxonMobil and Chevron accounted for approximately 14 percent and 11 percent of the Company’s total revenues, respectively. ExxonMobil accounted for approximately $54.8 million of the Company’s international drilling segment revenues and approximately $18.2 million of the Company’s rental tools segment revenues. Chevron accounted for approximately $50.6 million of the Company’s international drilling segment revenues and approximately $9.2 million of the Company’s rental tools segment revenues.

(2)		Drilling and rental operating income — drilling and rental revenues less direct drilling and rental 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	2007			2006			2005
	(Dollars in Thousands)
Drilling and rental revenues:
United States	$	369,170		$	309,757		$	218,056
Latin America		75,683			31,466			67,954
Asia Pacific		67,037			79,665			58,623
Africa and Middle East		14,580			24,219			33,377
CIS		128,103			141,328			153,652

Total drilling and rental revenues		654,573			586,435			531,662

Drilling and rental operating income (loss):
United States (1)		158,778			136,690			77,560
Latin America (1)		26,825			(5,679	)		4,018
Asia Pacific (1)		10,670			19,884			14,353
Africa and Middle East (1)		(14,466	)		(2,594	)		(834	)
CIS (1)		18,914			19,238			27,162

Total drilling and rental operating income		200,721			167,539			122,259


General and administrative expense		(24,708	)		(31,786	)		(27,830	)
Provision for reduction in carrying value of certain assets		(1,462	)		—			(4,884	)
Gain on disposition of assets, net		16,432			7,573			25,578


Total operating income		190,983			143,326			115,123

Interest expense		(25,157	)		(31,598	)		(42,113	)
Changes in fair value of derivative positions		(671	)		40			2,076
Loss on extinguishment of debt		(2,396	)		(1,912	)		(8,241	)
Equity in loss of unconsolidated joint venture and related charges		(27,101	)		—			—
Minority interest		(1,000	)		(229	)		1,905
Other		7,143			7,808			1,478

Income (loss) from continuing operations before income taxes	$	141,801		$	117,435		$	70,228


Long-lived assets: (2)
United States	$	447,235		$	401,349
Latin America		54,415			17,217
Asia Pacific		29,200			24,420
Africa and Middle East		59,067			2,412
CIS		96,286			90,389

Total long-lived assets	$	686,203		$	535,787


(1)		Drilling and rental operating income — drilling and rental revenues less direct drilling and rental 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.

Note 13 — Commitments and Contingencies

At December 31, 2007, the Company had a $60.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2007, $12.9 million of availability has been reserved to support letters of credit that have been issued and $20.0 million of loans outstanding under the facility.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Commitments and Contingencies (continued)

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, 2007, under operating leases with non-cancelable terms are as follows (dollars in thousands):


2008	$	4,450
2009		2,260
2010		873
2011		767
2012		152

Total	$	8,502

Total rent expense for all operating leases amounted to $10.1 million for 2007, $9.0 million for 2006 and $10.2 million for 2005.

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, 2007, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $8.2 million and the related insurance recoveries/receivables were $3.0 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 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Commitments and Contingencies (continued)

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 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

Contrary to two previous rulings on this precise issue, the May 24, 2006, ruling of the SCK affirmed the Income Tax Assessment. The SCK stayed enforcement and supervisory review to allow the Competent Authorities from the U.S. and the Republic of Kazakhstan to address this matter under the Mutual Agreement Procedure (“MAP”) of the U.S.-Kazakhstan Tax Treaty (the “Tax Treaty”), but when the Competent Authorities met on March 20-22, 2007, they were unable to achieve mutual agreement as to which country may tax the income in issue under the Tax Treaty.

On July 30, 2007, the supervisory panel of the SCK affirmed the May 24, 2006 ruling upholding the income tax assessment of MinFin and on August 7, 2007, MinFin issued a notice of assessment of corporate income taxes of approximately US$40 million and interest of approximately US$33 million. PKD Kazakhstan immediately filed a Complaint Against the Notice (“Complaint”) and MinFin acknowledged receipt of this Complaint and that no enforcement action would occur pending resolution of the Complaint pursuant to the MAP of the Tax Treaty. The Competent Authorities re-convened on October 8-11, 2007, to address the double taxation issue, but has not issued a protocol of resolution under the Tax Treaty.

On December 12, 2007, PKD Kazakhstan paid the tax portion of the Income Tax Assessment, net of any pre-paid taxes. In January 2008, PKD Kazakhstan filed an appeal against the interest portion of the notice of assessment. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Overview and Outlook”, Recent Events.

The full amount of the interest has been accrued pursuant to FIN 48. See Note 7, “Income Taxes”.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Commitments and Contingencies (continued)

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.

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 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 reaped dismissals with prejudice, two dismissals without prejudice and two withdraws from Group I, leaving only 40 plaintiffs remaining in Group I.

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, 2007.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Commitments and Contingencies (continued)

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 intends to confer with the EPA 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. The EPA and the other two parties have spent over $2.5 million studying and conducting initial remediation of the site, and it is anticipated that an additional $1.3 million will be required to complete the remediation. The Company does not believe we have any obligation with respect to the remediation of the property, and accordingly no accrual was made as of December 31, 2007. See Business, Environmental Considerations in Part 1, Item 1 of this Form 10-K.

Freight Forwarding and Customs Agent Request

During the third quarter of 2007, the U.S. Department of Justice (“DOJ”) requested that the Company provide certain information regarding its utilization of the services of a freight forwarding and customs agent during the past five years to verify if the services provided by this agent were in compliance with the Foreign Corrupt Practices Act. In response to this request, the Company has provided the requested information to DOJ. In January 2008, the Securities and Exchange Commission (“SEC”) requested the same information that the Company provided to DOJ, and the Company has also provided certain information to the SEC pursuant to the SEC’s request. The Company is fully cooperating with both DOJ and SEC with regard to this matter.

Saudi Arabia Joint Venture

The commitments and contingencies attributable to the Saudi Arabia Joint Venture are addressed in Note 8 — Saudi Arabia Joint Venture.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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.

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.

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 Robert L. Parker, Sr., through a Parker family trust. Lease payments 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)

Lease Agreements (continued)

Effective January 1, 2007, the Company entered into a Ranch Lease Agreement under which the Company agreed to pay a daily usage fee/person for utilization of the ranches. During 2007, the Company incurred fees of $33,000 pursuant to the Ranch Lease Agreement. These fees were paid in early 2008.

Other Related Party Agreements

During 2007, one of the Company’s directors held the position of executive vice president and chief financial officer of Apache Corporation (“Apache”). During 2007, subsidiaries of the Company recognized $14.0 million in gross revenues for performance of drilling services and provision of rental tools for a subsidiary of Apache.

Note 15 — Supplementary Information

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.

At December 31, 2006, accrued liabilities included $8.1 million of deferred mobilization fees, $4.9 million of accrued mobilization costs, $6.2 million of accrued interest expense, $7.9 million of workers’ compensation liabilities and $22.3 million of accrued payroll and payroll taxes. Other long-term obligations included $2.0 million of workers’ compensation liabilities as of December 31, 2006.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 16 — Selected Quarterly Financial Data


	Quarter
Year 2007	First (2)		Second (2)		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

Drilling and rental operating income	$	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

Discontinued operations	$	—	$	—	$	—	$	—	$	—

Net income	$	29,994	$	16,860	$	22,653	$	34,571	$	104,078

Basic earnings per share: (1)

Income from continuing operations	$	0.28	$	0.15	$	0.21	$	0.31	$	0.95

Discontinued operations	$	—	$	—	$	—	$	—	$	—

Net income	$	0.28	$	0.15	$	0.21	$	0.31	$	0.95

Diluted earnings per share: (1)

Income from continuing operations	$	0.27	$	0.15	$	0.20	$	0.31	$	0.94

Discontinued operations	$	—	$	—	$	—	$	—	$	—

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 16 — Selected Quarterly Financial Data (continued)


	Quarter
Year 2006	First		Second		Third (2)		Fourth (2)		Total (2)
	(Dollars in Thousands Except Per Share Amounts)
					(Unaudited)
Revenues	$	147,334	$	145,988	$	146,783	$	146,330	$	586,435

Drilling and rental operating income	$	41,065	$	39,636	$	44,217	$	42,621	$	167,539

Operating income	$	33,819	$	34,186	$	40,553	$	34,768	$	143,326

Income from continuing operations	$	11,458	$	13,761	$	18,639	$	37,168	$	81,026

Discontinued operations	$	—	$	—	$	—	$	—	$	—

Net income	$	11,458	$	13,761	$	18,639	$	37,168	$	81,026

Basic earnings per share: (1)

Income from continuing operations	$	0.11	$	0.13	$	0.17	$	0.35	$	0.76

Discontinued operations	$	—	$	—	$	—	$	—	$	—

Net income	$	0.11	$	0.13	$	0.17	$	0.35	$	0.76

Diluted earnings per share: (1)

Income from continuing operations	$	0.11	$	0.13	$	0.17	$	0.34	$	0.75

Discontinued operations	$	—	$	—	$	—	$	—	$	—

Net income	$	0.11	$	0.13	$	0.17	$	0.34	$	0.75


(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 $1.9 million gain in the third quarter of 2006 related to the receipt of insurance proceeds for a damaged rig discussed in Note 2. Also included is a gain on the disposition of assets for barge rigs in Nigeria, Barge Rig 57, Barge Rig 255, and certain other equipment of $2.1 million and $4.3 million in the second and third quarters of 2006, respectively. Net income in the fourth quarter includes the reversal of the remaining $12.6 million valuation allowance related to net operating loss state carryforwards. See Note 7 in the notes to the consolidated financial statement.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 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.


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

On March 15, 2007, the Audit Committee of the Board of Directors of the Company engaged KPMG LLP (“KPMG”) effective March 15, 2007 to serve as the Company’s independent registered public accounting firm to audit the Company’s financial statements for the fiscal year ending December 31, 2007. During the Company’s two most recent years ended December 31, 2006, and through KPMG’s appointment, the Company did not consult with KPMG with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s financial statements, and neither a written report was provided to the Company or oral advice was provided that KPMG concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (2) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K, or a reportable event, as that term is defined in Item 304(a)(1)(v) of Regulation S-K.

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, 2007. 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, 2007 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, 2007.

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

Changes in Internal Control over Financial Reporting — There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information with respect to directors can be found under the caption; “Item 1 — Election of Directors” and “Board of Directors” of the Company’s 2008 Proxy Statement for the Annual Meeting of Shareholders to be held on April 24, 2008. 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 2008 Proxy Statement for the Annual Meeting of Shareholders to be held on April 24, 2008 and is incorporated herein by reference.

The information in the Company’s 2008 Proxy Statement for the Annual Meeting of Shareholders to be held on April 24, 2008 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,” “2007 Director Compensation Table,” “Option/SAR Grants in 2007 to Non-Employee Directors,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Company’s 2008 Proxy Statement for the Annual Meeting of Shareholders to be held on April 24, 2008 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 2008 Proxy Statement for the Annual Meeting of Shareholders to be held on April 24, 2008.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item is hereby incorporated by reference to such information appearing under the caption “Certain Relationships and Related Party Transactions” and “Director Independence Determination” in the Company’s 2008 Proxy Statement for the Annual Meeting of Shareholders to be held April 24, 2008, to be filed with the SEC within 120 days of the end of the Company’s year ended December 31, 2007.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is hereby incorporated by reference from the information appearing under the caption “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 2008 Proxy Statement for the Annual Meeting of the Shareholders to be held April 24, 2008.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

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


	PAGE

Report of KPMG LLP — Independent Registered Public Accounting Firm		47
Report of PricewaterhouseCoopers LLP — Independent Registered Public Accounting Firm.		49
Consolidated Statement of Operations for the years ended December 31, 2007, 2006 and 2005		49
Consolidated Balance Sheet as of December 31, 2007 and 2006		50
Consolidated Statement of Cash Flows for the years ended December 31, 2007, 2006 and 2005		52
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2007, 2006 and 2005		54
Notes to the Consolidated Financial Statements		55

(2) Financial Statement Schedule:


Schedule II — Valuation and qualifying accounts			103

(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). Supplemental Indentures

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


EXHIBIT
NUMBER		DESCRIPTION

		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.

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).

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)	—	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(c)	—	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(d)	—	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(e)	—	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(f)	—	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(g)	—	2005 Long Term Incentive Plan (“2005 LTIP”) (incorporated by reference to the Company’s 2005 Proxy Statement dated March 22, 2005).*

10(h)	—	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).*

10(i)	—	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(j)	—	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(k)	—	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(l)	—	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(m)	—	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).*

100


EXHIBIT
NUMBER		DESCRIPTION

10(n)	—	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(o)	—	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(p)	—	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(q)	—	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(r)	—	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(s)	—	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(t)	—	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(u)	—	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(v)	—	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(w)	—	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(x)	—	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(y)	—	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).

10(z)	—	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

24.1	—	Report on schedule of KPMG 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

101

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, 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)	$	—

Year ended December 31, 2005:
Allowance for doubtful accounts and notes	$	3,591	$	613	$	—		$	2,565		$	1,639
Reduction in carrying value of rig materials and supplies	$	6,468	$	1,200	$	—		$	4,217		$	3,451
Deferred tax valuation allowance	$	56,003	$	—	$	15,494	(3)	$	71,497	(4)	$	—


(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.

(3)		During 2005 and prior to the reversal of the valuation allowance, the Company completed a process of reconciling its United States federal 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 $15.5 million. Additionally, the Company increased its valuation allowance by $15.5 million resulting in no impact to the net deferred tax asset.

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

102

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.
Date: February 29 , 2008		Robert L. Parker Jr.
		Chairman, Chief Executive Officer and Director

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 29, 2008

By:	/s/ James W. Whalen James W. Whalen	Vice Chairman of the Board and Director	February 29, 2008

By:	/s/ David C. Mannon David C. Mannon	President and Chief Operating Officer	February 29, 2008

By:	/s/ W. Kirk Brassfield W. Kirk Brassfield	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 29, 2008

By:	/s/ Lynn G. Cullom Lynn G. Cullom	Controller (Principal Accounting Officer)	February 29, 2008

By:	/s/ George J. Donnelly George J. Donnelly	Director	February 29, 2008

By:	/s/ John W. Gibson, Jr. John W. Gibson, Jr.	Director	February 29, 2008

By:	/s/ Robert W. Goldman Robert W. Goldman	Director	February 29, 2008

By:	/s/ Robert E. McKee III Robert E. McKee III	Director	February 29, 2008

By:	/s/ Roger B. Plank Roger B. Plank	Director	February 29, 2008

By:	/s/ R. Rudolph Reinfrank R. Rudolph Reinfrank	Director	February 29, 2008

103


		PAGE
	PART I

Item 1.	Business		3
Item 1A.	Risk Factors		12
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		24
Item 3.	Legal Proceedings		26
Item 4.	Submission of Matters to a Vote of Security Holders		26

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		27
Item 6.	Selected Financial Data		29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		46
Item 8.	Financial Statements and Supplementary Data		47
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		96
Item 9A.	Controls and Procedures		97
Item 9B.	Other Information		98

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance		98
Item 11.	Executive Compensation		98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		98
Item 13.	Certain Relationships and Related Transactions		99
Item 14.	Principal Accounting Fees and Services		99

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		99
Signatures			103
Subsidiaries of the Registrant
Report of Independent Registered Public Accounting Firm
Consent of PricewaterhouseCoopers LLP
Report on Schedule
Robert L. Parker Jr., Chairman, President and CEO, Rule 13a-14(a)/15d-14(a) Certification
W. Kirk Brassfield, Senior Vice President and CFO, Rule 13a-14(a)/15d-14(a) Certification
Robert L. Parker Jr., Chairman, President and CEO, Section 1350 Certification
W. Kirk Brassfield, Senior Vice President and CFO, Section 1350 Certification


	2007				2006
Quarter	High		Low		High		Low
First	$	9.76	$	7.50	$	12.44	$	8.07
Second		12.10		9.40		9.84		6.10
Third		11.65		7.01		7.65		6.25
Fourth		9.07		6.70		10.05		6.50


	Drilling Depth Rating in Feet
	10,000		10,000			Over
Region	or Less		25,000			25,000		Total
Asia Pacific		1		8	(1)		—		9
CIS		—		5			3		8
Latin America		—		3			5		8
Africa/Middle East		—		7	(2)		0		7

Total		1		23			8		32


(1)		Rig 206 was sold in early 2008.

(2)		Four are in a 50% owned joint venture in Saudi Arabia with two additional rigs under construction.


			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		2003		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
Rig No. 23 (2)		1,000		1993		13,000


	1991 Stock
	Grant Plan
	Restricted
	Shares

Outstanding at December 31, 2006		100,000

Granted		—
Exercised		(100,000	)
Cancelled		—


Outstanding at December 31, 2007		—


	1994 Non-Employee
	Director Stock Incentive Plan
				Weighted
				Average
				Exercise		Intrinsic
	Shares			Price		Value
Outstanding at December 31, 2006		84,000		$	9.047

Granted		—			—
Exercised		(30,000	)		8.875	$	33,150
Cancelled		(40,000	)		8.984

Outstanding at December 31, 2007		14,000			9.573


	1994 Executive Stock Option Plan
	Incentive Options							Non-Qualified Options
				Weighted							Weighted
				Average							Average
				Exercise		Intrinsic					Exercise		Intrinsic
	Shares			Price		Value		Shares			Price		Value
Outstanding at December 31, 2006		101,403		$	8.875				618,597		$	8.875

Granted		—			—				—			—
Exercised		(101,403	)		8.875	$	147,203		(618,597	)		8.875	$	890,677
Cancelled		—			—				—			—

Outstanding at December 31, 2007		—		$	—				—		$	—


	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		Shares		Per-Share
	(Numerator)		(Denominator)		Amount
Basic EPS:
Income from continuing operations	$	81,026,000		106,552,015	$	0.76
Discontinued operations		—				—


Net income	$	81,026,000			$	0.76

Effect of dilutive securities:
Stock options and restricted stock				1,586,368	$	(0.01	)

Diluted EPS:
Income from continuing operations	$	81,026,000		108,138,383	$	0.75
Discontinued operations		—				—


Net income	$	81,026,000			$	0.75