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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, 2005
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE TRANSITION PERIOD FROM _________ TO _________

COMMISSION FILE NUMBER 1-7573

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)


Delaware		73-0618660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Exchange Act Rule 12b-2. Large accelerated filer þ Accelerated filer o Non-accelerated filer 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, 2005 was $631.3 million. At January 31, 2006, there were 107,781,704 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our definitive proxy statement for the 2006 annual meeting of shareholders 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 after having been established in 1934 by its founder, Gifford C. Parker. The founder was the father of Robert L. Parker, chairman and a principal stockholder, and the grandfather of Robert L. Parker Jr., president and chief executive officer. 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 to, the Securities and Exchange Commission (“SEC”). Additionally, these reports are available on an Internet website maintained by the SEC. The address of that site is 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 51 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 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 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, 2005, our fleet of rigs available for service consisted of:


	•	eight land rigs in the Commonwealth of Independent States (“CIS”);

	•	nine land rigs in the Asia Pacific region;

	•	seven land rigs in Mexico;

	•	two barge drilling rigs in the “transition zones” (coastal waters that include lakes, bays, rivers and marshes) of Nigeria;

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

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

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

Our Rental Tools Business

A subsidiary of Parker Drilling, 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-

ITEM 1. BUSINESS (continued)

Our Rental Tools Business (continued)

pressure blowout preventers, choke manifolds, junk and cement mills and casing scrapers. Approximately two-thirds 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. Expansions have included two rental facilities in Texas and one in the Rocky Mountain area. 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 internationally to Mexico, Russia and Equatorial New Guinea.

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 transition zones, primarily in Louisiana, and to a lesser extent, in Alabama and Texas. Drilling rigs and related gathering and transportation systems in the area are subject to a variety of tropical storms, ranging from minor disturbances to intensely destructive hurricanes.

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, and 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. Historically there have been a small number of competitors in international markets due to the remote locations and difficult drilling conditions, however a number of national drilling companies are now entering these markets due to a higher level of sustained oil and gas prices. A substantial portion of operations are in foreign countries and are subject to the risks incidental to those operations as more fully described in Item 1A Risk Factors.

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 innovative drilling and rental tools services. During the fourth quarter of 2005, we implemented a five-year strategic plan that sets out our strategy for accomplishing these goals. Key elements in our strategy include:

Pursuing Strategic Growth Opportunities. In our contract drilling business, emphasis will be on creating a fleet of premium rigs that will be utilized regardless of the position in the energy business cycle. In 2006, we are involved in the construction of nine new rigs, including four new land rigs for use in international markets and one new deep drilling barge rig for use in the U.S. Gulf of Mexico. In addition, our recently announced joint venture in Saudi Arabia has contracted to provide four new land rigs. Significant upgrades to convert a barge rig to deep drilling capability for use in the U.S. Gulf of Mexico market are also underway. Expansions for our rental tools business are also planned for mid-2006 and will include the addition of a new storage and inspection location.

We will also continue to grow our project management business in 2006. In 2005, we were able to upgrade some of our labor contracts to full operations and maintenance (“O&M”) contracts and will continue to further use our competitive advantages in safety, preventive maintenance, inventory control and training to add more of these contracts. These projects are expected to add attractive cash flows to our current profitable base of operations without significant capital outlays.

Sustaining the High Utilization of Our Barge and Land Rigs. Another of our strategic objectives is to sustain the high utilization of our barge and land rigs with strategic placement and preventive maintenance that will maximize operating efficiency and minimize down time. Rig utilization increased to 78 percent in 2005 from 60 percent in 2004 due not only to improved market conditions, but also to marketing strategies implemented in late 2004.

Focusing on an Efficiency-Based Operating Philosophy for Operating Costs, Preventive Maintenance and Capital Expenditures. We continue to be vigilant in minimizing embedded administration and operations costs.

ITEM 1. BUSINESS (continued)

Our Strategy (continued)

During 2005 we implemented systems that facilitate the review of all costs and expect even further application of these processes in 2006. Our operating philosophy emphasizes continuous improvement of processes, equipment standardization and global quality, safety and supply chain management. Capital expenditures will be aligned with core objectives and aggressive preventive maintenance programs.

Continuing to Reduce Our Debt to Capitalization Ratio and Enhance Our Liquidity. Our initial debt reduction goal of $200 million set in December 2002 was met and exceeded in late 2005. Going forward we will continue to improve our debt to capitalization ratio. Liquidity will also be positively affected by reduced interest payments due to lower levels of long-term debt, lower interest rates achieved through exchange of higher priced debt with lower priced debt and the elimination of the costs associated with debt retirement and exchanges. We also successfully completed a $99.9 million equity offering in mid-January 2006 from which the proceeds will be used in growth projects.

Our Competitive Strengths

Our competitive strengths have historically contributed to our operating performance and we believe the following strengths should make our outlook for the future strong:

Geographically Diverse Operations and Assets. We currently operate in Bangladesh, China, Colombia, Indonesia, Kazakhstan, Kuwait, Mexico, New Zealand, Nigeria, Papua New Guinea, Russia, Turkmenistan and the United States and have recently entered into a joint venture to operate in Saudi Arabia. Since our founding in 1934, we have operated in 51 foreign countries and the United States, making us among the most geographically diverse drilling contractors in the world. Our international revenues constituted approximately 59 percent of our total revenues in the twelve months ended December 31, 2005. Our core international land drilling operations focus primarily on the CIS region, where we have eight land rigs; the Asia Pacific region, where we have nine land rigs, including seven helicopter transportable rigs; and Mexico, where we have been operating seven land rigs. Our international offshore drilling operations focus on the Caspian Sea, where we own and operate the world’s largest arctic-class barge rig; Mexico, where we have one barge rig; and Nigeria, where we have two barge rigs. We also have 19 drilling and workover barge rigs in the 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 the operations of our barge and land rigs. In 2005 we achieved the lowest Total Recordable Incident Rate (“TRIR”) of any drilling contractor. Our safety record, as evidenced by our low TRIR, has made us a leader in occupational injury prevention for the last nine years. 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.

Strong and Experienced Senior Management Team. Our management team has extensive experience in the contract drilling industry. Our chairman, Robert L. Parker, joined Parker Drilling in 1948 and served as our chief executive officer from 1969 to 1991. Robert L. Parker Jr. joined Parker Drilling in 1973 and has served as our president and chief executive officer since 1991. Under the leadership of Mr. Parker and Mr. Parker Jr., we have developed a 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. Prior to joining Parker Drilling, 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 24 years of experience to our drilling operations which will enhance our ability to achieve our goals of increased utilization and profitable growth. As part of our succession planning, in October 2005, James W. Whalen, senior vice president and chief financial officer was appointed to the board of directors and named vice chairman and W. Kirk Brassfield was named senior vice president and chief financial officer. Mr. Brassfield joined Parker Drilling in 1998 and has served in several executive positions including vice president, controller and principal accounting officer. He brings 26 years of experience to the management team, including 14 years in the oil and gas industry.

ITEM 1. BUSINESS (continued)

Project Management

We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we mobilized a new rig to Sakhalin Island which we designed, constructed and sold to Exxon Neftegas Limited (“ENL”). Drilling operations under a five-year O&M contract with ENL began in June 2003. In the third quarter of 2004, we began supervising construction of a second rig to drill in this area, the Orlan platform. The platform was moved from its construction site in Korea late in the third quarter of 2005 and began a five-year O&M contract for ENL offshore Sakhalin in September 2005. We also began a third O&M contract in late 2005 utilizing a third party rig to perform workover operations in Sakhalin Island for ENL.

We upgraded two of our labor service contracts in Papua New Guinea to full O&M contracts in the third quarter of 2005. As of December 31, 2005, we not only had O&M contracts in Sakhalin Island and Papua New Guinea, but were actively providing labor services on third party-owned drilling rigs in Kuwait, China and Colombia.

Competition

The contract drilling industry is a highly competitive business characterized by high capital requirements and challenges in securing and retaining qualified field personnel.

We are one of two major contractors that compete in the U.S. Gulf of Mexico barge drilling market. In international land markets, we compete with a number of international drilling contractors as well as smaller local contractors. National drilling contractors have increased competition in international markets in recent years. These national drilling contractors can typically operate at lower costs due to reduced labor and import costs. However, we are generally able to distinguish ourselves from these national companies based on our technical expertise and experience as well as our safety record. In international land and offshore markets, our experience in operating in challenging environments and our customer alliances have both been factors 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. See Item 1A for additional information.

Customers

We have developed a reputation for providing efficient, safe, environmentally conscious and innovative drilling services. 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 at 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 quality of equipment, personnel, safety program, service and experience.

Our drilling and rental tools customer base consists of major, independent and national-owned oil and gas companies and integrated service providers. In 2005, ExxonMobil and its ventures accounted for approximately 14 percent of our total revenues, and ChevronTexaco and a consortium in which Chevron is a partner, Tengizchevroil (“TCO”) accounted for approximately 11 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 61 percent of our total revenues in 2005.

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 a basic 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 well or number of wells. The contract term in some

ITEM 1. BUSINESS (continued)

Contracts (continued)

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 certain cases we are able to obtain a 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 that such insurance will not adequately protect us against or not be available to cover all the liability from all of the consequences and hazards we may encounter in our drilling operations. In addition, our 2006 insurance renewal negotiations may be adversely affected as a result of the hurricanes in the U.S. Gulf of Mexico and our other recent insurance claims.

Employees

The following table sets forth the composition of our employees:


	December 31,
	2005		2004

International drilling		2,113		2,110
U.S. drilling		564		565
Rental tools		175		169
Corporate and other		188		170

Total employees		3,040		3,014

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.

ITEM 1. BUSINESS (continued)

Environmental Considerations (continued)

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.

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.

ITEM 1. BUSINESS (continued)

Environmental Considerations (continued)

Our operations are also governed by laws and regulations related to workplace safety and worker health, primarily the Occupational Safety and Health Act and regulations promulgated thereunder. In addition, various other governmental and quasi-governmental agencies require us to obtain certain miscellaneous permits, licenses and certificates with respect to our operations. The kind of permits, licenses and certificates required in our operations depend upon a number of factors. We believe that we have all such miscellaneous permits, licenses and certificates that are material to the conduct of our existing business.

CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response and remediation costs, as well as natural resource damages. Few defenses exist to the liability imposed by CERCLA. We have received an information request under CERCLA designating 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 are continuing to evaluate our relationship to the site and have not yet estimated the amount or impact on our operations, financial position or cash flows of any costs related to the site.

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.

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

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

We operate in 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, 2005, 2004 and 2003 is set forth in Note 11 in the notes to the consolidated financial statements.

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.

ITEM 1A. RISK FACTORS (continued)

Risk Factors Related to Our Business

Failure to retain key personnel could hurt 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.

We have substantial indebtedness. Our ability to service our debt obligations is primarily dependent upon our future financial performance.

We have substantial indebtedness in relation to our stockholders’ equity. As of December 31, 2005, we had stockholders’ equity of approximately $259.8 million compared to approximately:


	•	$380.0 million of long-term debt;

	•	$13.3 million of operating lease commitments; and

	•	$10.3 million of standby letters of credit.

Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations.

We realized positive cash flows from operating activities of $122.6 million in 2005, $28.8 million in 2004, and $62.5 million in 2003, and were successful with a $99.9 million equity offering in January 2006. 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.

Our substantial 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;

	•	expose us to interest rate risk because certain of our borrowings and our Senior Floating Rate Notes, or interest rate swaps related to those borrowings, are at variable rates of interest; and

	•	make us more vulnerable to downturns in our business.

We cannot give you any assurances that, if we are unable to service our debt obligations, we will be able to sell equity securities, sell additional assets or restructure or refinance our debt. Our ability to generate sufficient cash

ITEM 1A. RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

flow from operating activities to pay the principal of and interest on our indebtedness is subject to market conditions and other factors which are beyond our control.

Our current operations and future growth may require significant additional capital, and our substantial indebtedness could impair our ability to fund our capital requirements.

Our business requires substantial capital (we anticipate that our capital expenditures in 2006 will be approximately $240 million, including approximately $40 million for maintenance projects). We may require additional capital in the event of significant departures from our current business plan or unanticipated expenses. Sources of funding for our future capital requirements may include any or all of the following:


	•	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 highly leveraged capital structure, additional financing may not be available to us, or, if it were available, it may not be available on a timely basis, on terms acceptable to us and within the limitations contained in the indentures governing the 9.625% Senior Notes and our Senior Floating Rate 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.

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 in response to an inspection by a governmental authority. For example, in 2002, we were required to make repairs to two of our barge rigs in Nigeria to maintain our certification with the American Bureau of Shipping, resulting in downtime of a total of five months during which time we received no revenues. We may also make significant expenditures when we move rigs from one location to another, such as when we moved barge rig 72 from Nigeria to the U.S. Gulf of Mexico in 2004. Additionally, we may make substantial expenditures for the construction of new rigs. 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 material or skilled labor;

	•	unforeseen engineering problems;

	•	unanticipated change orders;

	•	work stoppages;

	•	adverse weather conditions;

	•	long lead times for manufactured rig components;

	•	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)

Risk Factors Related to Our Business (continued)

Volatile oil and natural gas prices impact demand for our drilling and related services.

The success of our drilling 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 effect on our operations in the Gulf of Mexico.

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


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

	•	advances in exploration, development and production technology;

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

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

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

	•	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 gas reserves;

	•	the availability of pipeline capacity; and

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

Oil and gas prices have increased significantly since 2003 based primarily on worldwide demand and political instability. There is historical support that current prices are not sustainable over the long term. Based on recent history of our industry, fluctuations during the past several years in the demand and supply of oil and natural gas have contributed to, and are likely to continue to contribute to price volatility. Any actual or anticipated reduction in oil and natural gas prices would depress the level of exploration and production activity. This would, in turn, result in a corresponding decline in the demand for our drilling and related services which would adversely affect our business and financial performance.

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. Also, customers may seek to renegotiate the terms of their existing drilling contracts during depressed market conditions. Although drilling conditions are currently favorable, in the event the market becomes depressed, customers are more likely to exercise their termination rights.

Our customers may also seek to terminate drilling contracts if we experience operational problems and customers are more likely to exercise their termination rights during depressed market conditions. 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.

ITEM 1A. RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

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 2005, ExxonMobil and its ventures accounted for approximately 14 percent of our total revenues, and ChevronTexaco and a consortium in which Chevron is a partner, TCO, accounted for approximately 11 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 61 percent of our total revenues in 2005. Our results of operations could be adversely affected if any of our major customers terminate their contracts with us, fail to renew our existing contracts or refuse to award new contracts to us.

Contract drilling and the rental tools business are highly competitive.

The contract drilling and rental tools markets are highly competitive, and no single competitor is dominant. Although the drilling market is currently experiencing a strong upward trend, during periods of decreased demand we historically experience significant reductions in utilization. We anticipate that current demand for oil and gas will result in higher utilization rates for the foreseeable future. However, if commodity prices decline again 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. 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. Despite high commodity prices at present, 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 significantly greater financial resources than we do.

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

We have operations in 12 foreign countries and have recently contracted, through a joint venture, for work in Saudi Arabia. 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, or such policies may only be available with premiums that are not commercially justifiable. For example, significant civil unrest in Nigeria, which is continuing, has resulted in the suspension of drilling operations of our rigs in Nigeria for substantial periods during the past two years and again beginning in February 2006. In 2003, civil disturbances resulted in the total loss of one of our rigs in Nigeria, a substantial portion of which we recovered from insurance.

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 2004 and 2005, we derived approximately 59 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;

	•	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; and

	•	foreign currency fluctuations and restrictions on currency repatriation.

ITEM 1A. RISK FACTORS (continued)

Risk Factors 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.

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 12 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 Kazakhstan and other countries in which we do business, and these disputes could have a material adverse effect on our financial performance.

We are subject to hazards customary for drilling operations, which could adversely affect our financial performance if we are not adequately indemnified or insured.

Substantially all of our operations are subject to hazards that are customary for oil and gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and 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. For example, in June 2005, a well control incident resulted in a fire and damage to a rig in Bangladesh, resulting in a total loss of the drilling unit. In July 2005, we suffered damage to a deep drilling barge rig which ran aground and overturned and in November 2005 we sustained a well control incident in Turkmenistan. 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 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 a significant amount of 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. For further information, see Note 12 in the notes to the consolidated financial statements. There is no assurance that such insurance or indemnification agreements will 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

ITEM 1A. RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.

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.

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. For example, in September 2005, one of our subsidiaries was served with a lawsuit filed in the District Court of Houston, Texas. See Note 12 in the notes to the consolidated financial statements. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of these lawsuits to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits.

Risks Related to Our Common Stock

Market prices of our common stock could change significantly.

The market prices of our common stock may change significantly in response to various factors and events, including the following:


	•	the other risk factors described in this Form 10-K, including changes in oil and 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 oil and gas or oilfield service 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 dispute with the Ministry of Finance of the Republic of Kazakhstan. See Note 12 in the notes to the consolidated financial statements.

Most of these factors are beyond our control.

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

ITEM 1A. RISK FACTORS (continued)

Risks Related to Our Common Stock (continued)

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 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 our Senior Floating Rate Notes and the guarantees related to those notes are senior unsecured obligations of Parker Drilling and certain of our domestic 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 will 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; (ii) the stock of all of our direct and indirect domestic subsidiaries; and (iii) substantially all of the personal property assets of our rental tools business. In the event of a default on secured indebtedness, the parties granted security interests will have a prior secured claim on such assets. If the parties should attempt to foreclose on their collateral, our financial condition and the value of the notes would be adversely affected.

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

We conduct substantially all of our operations through our subsidiaries. As a result, our cash flows and our ability to service our debt, including our notes, is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory restrictions. 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, and we cannot assure you that we will be able to obtain the necessary funds from other sources.

Our notes are guaranteed by certain of our direct and indirect domestic subsidiaries, and an international subsidiary. As of December 31, 2005, our non-guarantor subsidiaries and joint ventures collectively owned approximately 18 percent of our consolidated total assets and held approximately $17.1 million of our consolidated cash and cash equivalents of approximately $60.2 million. In 2005, our non-guarantor subsidiaries and joint ventures had drilling and rental revenues of approximately $156.8 million and total operating income of approximately $1.6 million. The amount of our consolidated total assets and cash and cash equivalents held by, and the amount of our consolidated drilling and rental revenues and operating income derived from, our non-guarantor subsidiaries and joint ventures has increased in each of the last three years, and we expect that this trend will continue as we expand our international operations. See Note 5 to the notes to the consolidated financial statements.

ITEM 1A. RISK FACTORS (continued)

Risks Related to our Debt Securities (continued)

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

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


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

	•	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 may not be able to repurchase our notes upon a change of control.

Upon the occurrence of specific change of control events affecting us, the holders of our 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 cannot assure you that we will 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 indentures governing our 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.

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

ITEM 1A. RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS (continued)

historical facts, are “forward-looking statements” for purposes of these provisions, including any statements regarding:


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

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

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

	•	our future operating results and profitability;

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

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

	•	growth of the Company through acquisitions of companies or assets;

	•	entering into joint venture agreements with local companies;

	•	our future capital expenditures and investments in the acquisition and refurbishment of rigs and equipment;

	•	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 dispute with the Ministry of Finance of the Republic of Kazakhstan;

	•	our recovery of insurance proceeds with respect to our damaged assets;

	•	the availability of insurance coverage and contractual indemnification for pending legal proceedings;

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


	•	expansion and growth of our operations.

In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses made by our management in light of their experience and perception of historical trends, current conditions, expected future developments and other factors they believe are relevant. Although our management believes that their assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The factors listed in the “Risk Factors” section of this Form 10-K, 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. Each forward-looking statement speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.


ITEM 1B.	*UNRESOLVED STAFF COMMENTS*

None.


ITEM 2.	*PROPERTIES*

We lease office space in Houston for our corporate headquarters. Additionally, we own and lease office space and operating facilities in various locations, primarily to the extent necessary for administrative and operational support functions.

Land Rigs

The following table shows, as of December 31, 2005, the locations and drilling depth ratings of our 24 land rigs available for service. Twenty of these rigs were under contract and the remainder were available for contract as of December 31, 2005.


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

Asia Pacific (1)		1		8		—		9
CIS (2)		—		5		3		8
Latin America (3)		—		2		5		7

Total		1		15		8		24


(1)		One rig was removed from the marketable rig count August 1, 2005.

(2)		Two rigs are owned by AralParker.

(3)		Latin America includes rigs located in Mexico.

Barge Rigs

The following table shows our four international deep drilling barges as of December 31, 2005. All of these rigs were under contract at December 31, 2005.


			Year Built		Maximum
			or Last		Drilling
International	Horsepower		Refurbished		Depth (Feet)

Nigeria:
Rig No. 73		3,000		2002		30,000
Rig No. 75		3,000		1999		30,000
Caspian Sea:
Rig No. 257		3,000		1999		30,000
Mexico:
Rig No. 53		1,600		2004		20,000

ITEM 2. PROPERTIES (continued)

Barge Rigs (continued)

The following table shows our 19 deep, intermediate, and workover and shallow drilling barge rigs located in the U.S. Gulf of Mexico. Fourteen of these barge rigs were under contract and the remainder were available for contract as of December 31, 2005.


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

Deep drilling:
Rig No. 15		1,000		1998		15,000
Rig No. 50		2,000		2001		25,000
Rig No. 51		2,000		2003		25,000
Rig No. 54		2,000		1996		25,000
Rig No. 55		2,000		2001		25,000
Rig No. 56		2,000		2005		25,000
Rig No. 57		1,500		1997		20,000
Rig No. 72		3,000		2002		30,000
Rig No. 76		3,000		2004		30,000
Intermediate drilling:
Rig No. 8		1,000		1995		14,000
Rig No. 17		1,000		1993		13,000
Rig No. 20		1,000		2005		13,500
Rig No. 21		1,200		2001		14,000
Workover and shallow drilling:
Rig No. 6 (1)		700		1995		—
Rig No. 9 (1)		650		1996		—
Rig No. 12 (2)		1,100		1990		14,000
Rig No. 16		1,000		1994		13,500
Rig No. 23		1,000		1993		13,000
Rig No. 26 (1)		650		2005		—


(1)		Workover rig.

(2)		Currently being upgraded to a deep drilling barge rig.

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, 2005 and 2004.


	Year Ended December 31,
Transition Zone Rig Data	2005			2004

U.S. barge deep drilling:
Rigs available for service (1)		8.8			8.3
Utilization rate of rigs available for service (2)		92	%		92	%
U.S. barge intermediate drilling:
Rigs available for service (1)		4.0			5.0
Utilization rate of rigs available for service (2)		74	%		46	%
U.S. barge workover and shallow drilling:
Rigs available for service (1)		6.0			7.0
Utilization rate of rigs available for service (2)		56	%		42	%
International barge drilling:
Rigs available for service (1)		4.2			5.7
Utilization rate of rigs available for service (2)		96	%		43	%

International Land Rig Data
Rigs available for service (1)		29.9			38.0
Utilization rate of rigs available for service (2)		75	%		49	%


(1)		The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service for such year. Rigs available for service exclude rigs classified as assets held for sale. Our method of computation of rigs available for service may or 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 or may not be comparable to other similarly titled measures of other companies.


ITEM 3.	*LEGAL PROCEEDINGS*

For information on Legal Proceedings, see Note 12 in the notes to the consolidated financial statements of this annual report on Form 10-K, which information from Note 12 in the notes to the consolidated financial statements 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 2005.


ITEM 4A.	*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, 82, chairman, joined Parker Drilling in 1948 and was elected vice president in 1950. He was elected president in 1954 and chief executive officer and chairman in 1969. Since 1991, he has held only the position of chairman.


ITEM 4A.	*EXECUTIVE OFFICERS (continued)*

(2) Robert L. Parker Jr., 57, president 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. He has been a director since 1973.

(3) David C. Mannon, 48, senior vice president and chief operating officer, joined Parker Drilling in December 2004. 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.

(4) W. Kirk Brassfield, 50, 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.

(5) Denis J. Graham, 56, 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.

(6) Ronald C. Potter, 52, 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.

(7) Lynn G. Cullom, 51, 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, including vice president of financial reporting and planning for Coastal Mart, a subsidiary of Coastal Corporation from September 1979 through February 2001.

(8) Michael D. Drennon, 50, 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.

Other Parker Drilling Company Officer


	(9)	David W. Tucker, 50, 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.

PART II


ITEM 5.	*MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES*

Parker Drilling Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” At the close of business on December 31, 2005, there were 2,264 holders of record of Parker Drilling common stock. The following table sets forth the high and low closing prices per share of Parker Drilling’s common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:


	2005				2004
Quarter	High		Low		High		Low

First	$	6.15	$	3.75	$	4.49	$	2.55
Second		7.21		4.50		4.14		2.65
Third		9.66		6.79		4.03		2.97
Fourth		11.82		7.41		4.42		3.56

Substantially all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record. As of January 31, 2006, our common stock was held by 2,245 holders of record and an estimated 30,113 beneficial owners.

No dividends have been paid on common stock since February 1987. Restrictions contained in Parker Drilling’s existing credit agreement and the indentures for the Senior Notes restrict the payment of dividends. We have no present intention to pay dividends on our common stock in the foreseeable future because of the restrictions noted.

The information under the caption “Equity Compensation Plan Information” in Parker Drilling’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held on April 28, 2006, to be filed with the 2006 Proxy Statement, is incorporated herein by reference.

We purchased 78,049 shares at a price per share of $5.77 on March 11, 2005 and 4,761 shares at a price of $7.90 on August 6, 2005 from Parker Drilling executives resulting from the vesting of a portion of a restricted stock grant issued in July 2003 and August 2002, respectively. Upon vesting of the restricted shares, tax withholding obligations to Parker Drilling from the executives were satisfied by delivering back to Parker Drilling some of the shares on which the restrictions had lapsed.

Total Number

Maximum Number

of Shares Purchased

of Shares That May

as Part of Publicly

Yet be Purchased

Total Number of

Average Price

Announced Plans

Under the Plans

Date

Shares Purchased

Paid Per Share

or Programs

March 11, 2005

78,049

5.77

—

August 6, 2005

4,761

7.90

—

Subsequent to December 31, 2005, we announced the offering of 8,900,000 shares of common stock on January 18, 2006, pursuant to a Free Writing Prospectus dated January 17, 2006 and a Prospectus Supplement dated January 18, 2006. On January 23, 2006, we realized $11.23 per share or a total of $99.9 million of net proceeds before expenses, but after underwriter discount, from the offering.


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, 2005. 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,
	2005 (1)		2004			2003 (2)			2002 (3)			2001
	(Dollars in Thousands, Except Per Share Data)

Income Statement Data
Total drilling and rental revenues	$	531,662	$	376,525		$	338,653		$	385,714		$	452,944
Total operating income		115,123		23,867			22,927			38,556			65,100
Income (loss) from continuing operations		98,812		(50,565	)		(52,434	)		(21,193	)		2,327
Net income (loss)		98,883		(47,083	)		(109,699	)		(114,054	)		11,059
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	1.03	$	(0.54	)	$	(0.56	)	$	(0.23	)	$	0.03
Net income (loss)	$	1.03	$	(0.50	)	$	(1.17	)	$	(1.23	)	$	0.12
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	1.02	$	(0.54	)	$	(0.56	)	$	(0.23	)	$	0.03
Net income (loss)	$	1.02	$	(0.50	)	$	(1.17	)	$	(1.23	)	$	0.12

Balance Sheet Data
Cash and cash equivalents	$	60,176	$	44,267		$	67,765		$	51,982		$	60,400
Marketable securities		18,000		—			—			—			—
Property, plant and equipment, net		355,397		382,824			387,664			641,278			695,529
Assets held for sale		—		23,665			150,370			896			1,800
Total assets		801,620		726,590			847,632			953,325			1,105,777
Total long-term debt and capital leases, including current portion		380,015		481,063			571,625			589,930			592,172
Stockholders’ equity		259,829		148,917			192,803			300,626			412,143


(1)		The 2005 results reflect the reversal of a $71.5 million valuation allowance related to net operating loss carryforwards and other deferred tax assets. See Note 7 in the notes to the consolidated financial statements.

(2)		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.

(3)		In 2002, we adopted the Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” and recorded a goodwill impairment of $73.1 million as a cumulative effect of a change in accounting principle.


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

RESULTS OF OPERATIONS

Overview — Financial results for 2005 reflect the significant improvement over 2004 that we anticipated would result from strong market conditions, and from significantly reduced debt and interest costs associated with the achievement of our debt reduction goal. Demand has continued to grow, both domestically and internationally. Uncertainty over disruptions in supply of oil and gas has intensified due to continued geopolitical issues and, coupled with the impact of the tropical storms in the U.S., pushed the record high oil and gas prices of 2004 even higher in 2005. These market conditions resulted in increases in utilization and dayrates in most of our drilling segments and increased utilization and pricing in our rental tools operations during 2005. We anticipate that these market conditions will continue to positively impact our financial results for the foreseeable future.

Gross margin more than doubled in 2005, with a 79 percent increase from domestic drilling, predominantly driven by higher dayrates; a 45 percent increase from our rental tools business due both to increased activity and higher rates; and a 36 percent increase in our international drilling segment, due primarily to increased utilization and expansion of management and labor service contracts. We had gains on asset disposals of $25.6 million due primarily to our Latin America assets sale and insurance recoveries on damaged rigs and had $8.2 million lower asset impairments than in 2004. We also reduced “Other income and expense” by $14.5 million, which includes interest and debt extinguishment expenses, and had a net $44.9 million non-cash benefit primarily related to the release of the valuation allowance on deferred tax assets. These improvements resulted in net earnings of $98.9 million in 2005.

Our domestic utilization was 77 percent for 2005 overall, with utilization for our deep drilling barges at 92 percent. Dayrates in this region increased 29 percent. We believe that domestic utilization will remain at current levels and that there is still upside potential for dayrates during 2006. Utilization was also strong in both our international land and offshore drilling areas. In Mexico and New Zealand, all of our land rigs operated substantially all of 2005. In Papua New Guinea utilization was 92 percent, and our offshore international operations achieved 96 percent utilization.

Our rental tools segment, Quail Tools, continued to expand its U.S. market share and margins throughout 2005, and closed out 2005 with record revenues for the month of December. Demand has continued at high levels at each of our four facilities.

During 2005, we surpassed our $200 million debt reduction goal established at the end of 2002. Our outstanding debt balance of $589.9 million at December 31, 2002 was reduced to $380.0 million outstanding as of December 31, 2005. The debt reduction goal was achieved primarily through the sale of assets, insurance proceeds from involuntary conversion of rigs and cash generated from operations over the last two years. During 2005, we reduced debt by $101.0 million with proceeds from the sale of jackup rig 25, the sale of seven Latin America land rigs and existing cash. On December 30, 2005 we retired in full our outstanding 10.125% Senior Notes, leaving us with two series of outstanding Senior Notes. We have $225.0 million face value of 9.625% Senior Notes due October 2013 and $150.0 million of Senior Floating Rate Notes due September 2010. The combined effective weighted average interest rate on all of our notes is currently 9.3%.

Outlook — We expect continued strong results in 2006 as we grow the business with cash generated from enhanced operations and the $99.9 million in net cash proceeds generated from the stock offering we completed in mid-January 2006. As part of our plan for 2006 and beyond, we are currently constructing four land drilling rigs for use in international markets and one ultra-deep drilling barge for use in the U.S. Gulf of Mexico, and are converting workover barge rig 12 into a deep drilling barge. We also have expansions plans for our rental tools business beginning in mid-2006, including the addition of a new location. Overall, in 2006, we expect to increase capital expenditures to approximately $240.0 million.

We recently announced the formation of a 50 percent owned joint venture in Saudi Arabia to supply four new land rigs for a three-year initial term drilling contract with Saudi Aramco. The first rig is scheduled for delivery in the third quarter of 2006, with the three remaining rigs scheduled for delivery in the fourth quarter of 2006. Although the initial period of this joint venture will not generate significant profits or cash flows, it is part of the strategic growth in targeted markets set forth in our five-year plan. We expect to account for our interest in this joint venture utilizing the equity method.

Oil and gas price levels significantly impact exploration and production activity which in turn, impact both our contract drilling and rental tools revenues. In U.S. markets, drilling contracts are generally short-term, which has allowed us to benefit from rising prices over the last two years. To mitigate the risks from future changes in market conditions, we are negotiating longer term contracts in U.S. markets when possible. In international markets contracts are generally longer term, insulating us somewhat from short-term price fluctuations. Over extended periods, however, international market conditions typically follow the demand for oil. International markets also present the challenges of foreign regulation and civil unrest, which we continually monitor and apply risk management strategies to minimize. Our strategic plan focuses on leveraging our significant international experience, safety record, training, preventive maintenance programs and project management expertise, along with our innovative rig designs to help maintain higher utilization in periods of reduced drilling activity by being the contractor of choice.

RESULTS OF OPERATIONS (continued)

Outlook (continued)

As reported in our year end earnings release dated February 15, 2006, we expect 2006 net income to be in the $0.30 to $0.40 per diluted share range. Included in this estimate is depreciation of approximately $0.78 per diluted share, interest expense of approximately $0.36 per diluted share and income taxes of $0.35 per diluted share, including non-cash deferred taxes of $0.25 per diluted share.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

We recorded net income of $98.9 million for the year ended December 31, 2005, as compared to a net loss of $47.1 million for the year ended December 31, 2004. The loss from continuing operations for 2004 was $50.6 million, whereas substantially all of the net income for the year ended December 31, 2005 was from continuing operations. The income from discontinued operations was $71 thousand for 2005 compared to $3.5 million for 2004. Revenues increased $155.1 million to $531.7 million in 2005 as compared to 2004. The increase is attributed to higher utilization and dayrates in the U.S. barge operations, international land operations and our rental tools operations, Quail Tools.


	Year Ended December 31,
	2005				2004
	(Dollars in Thousands)

Drilling and rental revenues:
U.S. drilling	$	128,252		24%	$	88,512		23%
International drilling		308,572		58%		220,846		59%
Rental tools		94,838		18%		67,167		18%

Total drilling and rental revenues	$	531,662		100%	$	376,525		100%

Drilling and rental operating income:
U.S. drilling gross margin (1)	$	61,425		48%	$	34,386		39%
International drilling gross margin (1)		71,411		23%		52,395		24%
Rental tools gross margin (1)		56,627		60%		39,130		58%
Depreciation and amortization		(67,204	)			(69,241	)

Total drilling and rental operating income (2)		122,259				56,670
General and administrative expense		(27,830	)			(23,413	)
Provision for reduction in carrying value of certain assets		(4,884	)			(13,120	)
Gain on disposition of assets, net		25,578				3,730

Total operating income	$	115,123			$	23,867


(1)		Drilling and rental gross margins 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 as a percent of drilling and rental revenues. The gross margin amounts 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. We believe this information is useful to our investors because it more closely tracks 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

Year Ended December 31, 2005	(Dollars in Thousands)

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	$	61,425	$	71,411	$	56,627

Year Ended December 31, 2004

Drilling and rental operating income (2)	$	15,938	$	15,858	$	24,874
Depreciation and amortization		18,448		36,537		14,256

Drilling and rental gross margin	$	34,386	$	52,395	$	39,130


(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

U.S. drilling revenues increased $39.7 million in 2005 to $128.3 million due to higher utilization and dayrates. As of December 31, 2005 the U.S. drilling segment consisted of 19 barge rigs; nine deep drilling barge rigs, four intermediate drilling barge rigs and six workover barge rigs. Despite the destruction caused by Hurricanes Katrina and Rita, our U.S. Gulf of Mexico rigs sustained no material damage or downtime. Barge rigs 20 and 26 returned to service in late November after undergoing minor repairs and scheduled maintenance. Barge rig 57, which turned over during a move from the path of Hurricane Dennis in July, sustained additional damage during Hurricanes Katrina and Rita. Equipment on the rig was impaired by $2.6 million.

Average 2005 utilization for the barge rigs increased to 77 percent from an average utilization during 2004 of 63 percent. Average 2005 dayrates for the deep drilling barge rigs increased approximately $8,200 per day as compared to 2004. Overall, rate increases on all barge rigs accounted for $30.5 million of the revenue increase, and increased utilization accounted for approximately $9.2 million of the increase. As a result of higher dayrates and utilization, gross margins in the U.S. drilling segment increased $27.0 million to $61.4 million.

International Drilling Segment

International drilling revenues increased $87.7 million to $308.6 million in 2005 as compared to 2004. International land drilling revenues increased $58.8 million to $246.8 million and international offshore drilling revenues increased by $28.9 million to $61.8 million. International drilling gross margins increased by $19.0 million to $71.4 million due to increased margins of $12.6 million for international offshore and $6.4 million for international land operations.

International land drilling results improved primarily due to our operations in Mexico, the Asia Pacific countries of New Zealand, Papua New Guinea and Indonesia and on our Sakhalin Island O&M contracts in the CIS region. We completed our sale of certain Latin America assets previously operating in Colombia, Bolivia and Peru in the third quarter of 2005. The remaining seven Latin American land rigs were moved to Mexico in the second and third quarters of 2004 and worked throughout 2005 under contract with Halliburton de Mexico (“Halliburton”). Revenues for these rigs increased by $30.4 million to $50.2 million due to the full year of operation in 2005. The asset sales and move of rigs, combined for a decrease in revenues for the referenced Latin America countries of $6.4 million.

In our Asia Pacific region, revenues increased by $16.2 million as a result of 100 percent utilization for all three rigs in New Zealand compared to 78 percent in 2004 and higher dayrates in 2005, and utilization of 92 percent in 2005 as compared to 58 percent in 2004 for the two rigs in Papua New Guinea and higher dayrates in 2005, partially offset by a $2.1 million decline in Bangladesh in 2005 as compared to 2004 due to the loss of our rig 255 in a late June 2005 well control incident.

In our CIS region, revenues increased by $18.7 million due primarily to O&M revenues under our Sakhalin Island Orlan project of $24.6 million. Construction on this rig was completed in the second quarter of 2005 and full crews under our contract began in late September 2005. O&M revenues under our five-year service contract on rig 262, Sakhalin Island increased by $2.5 million to $30.2 million. Revenues also increased $2.3 million in Turkmenistan due to the addition of a third rig that began drilling in the third quarter of 2005, offset partially by a decrease in revenues on rig 247 which suffered a well control incident in November 2005. Due to the move of rig 236 to Turkmenistan in 2005, revenues in Russia declined by $5.1 million in 2005 as the rig worked approximately six months in 2004. Revenues also declined $5.0 million on our TCO contract as the scope of work under that contract was cut back with one TCO-owned rig released in late 2004, one in the third quarter of 2005 and rates reduced on rig 107, which was released in early January 2006.

International land gross margins increased $6.4 million in 2005 when compared to 2004. The increase is primarily the result of a full year of operations in Mexico ($4.9 million) and increased activity, as noted previously, related to our Orlan project in the CIS region ($3.0 million) and in New Zealand ($2.4 million), Papua New Guinea ($1.4 million) and Indonesia ($0.5 million) in the Asia Pacific region, offset partially by a decline related to our TCO contract of $5.9 million as previously discussed.

International offshore drilling revenues increased $28.9 million to $61.8 million in 2005 as compared to 2004. The increase in revenues is attributable to a $23.8 million increase in the Caspian Sea operation reflecting activation

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

of barge rig 257 in late 2004, whereas it had been stacked during most of 2004 and a $3.7 million increase for our offshore rig in Mexico as a result of a full year of operation in 2005. Our Nigerian operations had a $1.4 million increase in revenues due to less downtime in 2005.

International offshore gross margins increased $12.6 million in 2005 as compared to 2004. The increase is due to the operation of our rig in the Caspian Sea ($6.5 million) as mentioned above, whereas the rig was stacked in 2004. Costs to maintain the rig in a stacked condition were approximately $1.0 million per quarter in 2004 and we also settled an assessment of duties, taxes and penalties for this rig with the Customs Control in Mangistau, Kazakhstan, in the third quarter of 2004 for $2.1 million. In Nigeria, the gross margin increased $4.3 million as our two rigs operated most of the year versus lower utilization in 2004 and costs to maintain the barges in stacked condition and increased insurance costs caused by losses incurred. In addition, Nigerian tax authorities assessed additional Value Added Tax (“VAT”), resulting in a charge of $2.3 million in the second quarter of 2004. Mexico offshore gross margin increased by $1.8 million in 2005 due to a full year of operations as compared to seven months in 2004.

Rental Tools Segment

Rental tools revenues increased $27.7 million to $94.8 million in 2005. The increase in revenues was attributable to a 40 percent increase in rentals, a 114 percent increase in rental tools sales, a 50 percent increase in transportation revenues and a 43 percent increase in repair revenues. Increases were achieved at all locations, including a $0.6 million increase from our operations in New Iberia, Louisiana, $5.6 million in Victoria, Texas, $9.4 million in Odessa, Texas, $7.1 million in Evanston, Wyoming and $5.0 million from international sources. Gross margins increased $17.5 million due to the increased volume of business and granting of fewer discounts off listed rental prices.

Other Financial Data

Depreciation and amortization expense decreased $2.0 million to $67.2 million in 2005. The decrease is primarily attributable to asset sales completed during the year.

General and administrative expense increased $4.4 million to $27.8 million for the year ended December 31, 2005 as compared to 2004. The increase is due to the accelerated vesting of certain restricted stock in 2005 including our portion of payroll related taxes, amortization on the issuance of additional restricted stock in the second quarter 2005, higher compensation costs and higher staffing levels related to increased operating levels.

During 2005, we recognized a provision for reduction in carrying value of certain assets of $4.9 million as compared to $13.1 million in 2004. Damage to barge rig 57 in a July 2005 towing incident in preparation for a hurricane totaled approximately $2.6 million. We also wrote off the remaining $2.3 million relating to premiums paid on a life insurance policy for Robert L. Parker, chairman of the board and director. During 2004, we impaired two domestic workover barge rigs that were not marketable for $3.2 million, impaired two rigs in the amount $0.7 million in the Asia Pacific region, and recorded an impairment of $2.4 million to reduce the carrying value of all assets to net realizable value in Latin America in advance of the sale of the assets. During the second quarter of 2004 as required by GAAP, we reclassified our Latin America assets from discontinued operations to continuing operations as the assets had not sold within a year, or had a sale pending within a year. We recognized a $5.1 million charge to adjust the value of these assets to their fair value. The $5.1 million represents the depreciation that would have been recognized had the assets been continuously classified as held and used. In addition, during 2004 we reserved $1.7 million for an asset representing premiums paid in prior years on two split dollar life insurance policies for Robert L. Parker. The value of the asset was reduced and ultimately written off in relation to one of the policies as noted above. See Note 13 in the notes to the consolidated financial statements.

Gain on disposition of assets increased to $25.6 million in 2005 as compared to $3.7 million in 2004. The gain in 2005 was comprised of a $13.8 million gain on sale of Latin America assets, $10.5 million gain on the well control insurance proceeds related to rig 255 in Bangladesh and other miscellaneous asset sales of $1.3 million. In 2004, the $3.7 million gain was comprised of $0.9 million gain on the disposal of barge rig 74 and $2.8 million on sale of tubulars and scrap equipment.

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

Interest expense decreased $8.3 million to $42.1 million for the year ended December 31, 2005 as compared to 2004. The decrease in interest expense is attributable to the reduction of $101.0 million of our outstanding debt balance in 2005, the full year benefit from 2004 debt reductions and lower interest rates.

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements do not qualify for hedge accounting and accordingly, we are reporting the mark-to-market change in the fair value of the interest rate derivatives currently in earnings. For the year ended December 31, 2005, we recognized a non-cash increase in the fair value of the derivative positions of $2.1 million, as compared to a decrease in the fair value of the derivative position of $0.8 million in 2004.

Loss on extinguishment of debt was $8.2 million in 2005 compared to $8.8 million in 2004, as we reduced outstanding debt and exchanged higher interest rate debt for lower interest rate debt in both years. In February 2005, we repurchased $25.0 million of our 10.125% Senior Notes with the proceeds received from the sale of jackup rig 25 and cash on hand, recognizing an expense of $1.4 million for the 105.0625 percent redemption price on the repurchase of the notes and capitalized debt issuance costs associated with the notes. In April 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 recognized as long-term debt and is being amortized over the term of the notes. The additional notes were issued under an indenture dated October 10, 2003, under which $175.0 million in aggregate principal amount of notes in the same series were previously issued. On the same date that we issued the $50.0 million additional 9.625% Senior Notes, we issued a redemption notice for $65.0 million of our 10.125% Senior Notes at the redemption price of 105.0625 percent, resulting in a $3.3 million loss on the extinguishment of debt in the second quarter of 2005. During the third quarter of 2005 we redeemed $30.0 million of our 10.125% Senior Notes at a premium of $1.9 million using proceeds from the sale of our Latin American assets. On December 30, 2005, we retired the remaining $35.6 million of our 10.125% Senior Notes with cash on hand at a premium of $1.6 million.

We have a 50 percent interest in two joint ventures, which are included in our consolidated financial statements, and therefore we recognized minority interest income of $1.9 million in 2005 and minority interest expense of $1.1 million in 2004.

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 tax benefit of $46.5 million, current foreign tax expense of $14.5 million and foreign deferred tax expense of $1.6 million for the year ended December 31, 2005. For the year ended December 31, 2004, income tax expense from continuing operations consisted of foreign tax expense of $15.0 million. Foreign taxes decreased $0.5 million in 2005 due primarily to a reduction of taxes in Kazakhstan and Papua New Guinea offset by an increase in taxes related to the sale of the Latin American rigs and start up of the Orlan project in Russia. Our effective income tax rates for financial reporting purposes were approximately (41) percent and 42 percent for the years ended December 31, 2005 and 2004, respectively. The 2005 effective tax of (41) percent is lower than 2004 due primarily to the reversal of the valuation allowance related to net operating loss (“NOL”) carryforwards and other deferred tax assets in the U.S. The valuation allowance was originally recorded in accordance with GAAP as an offset to our deferred tax assets, which consisted primarily of NOL carryforwards. GAAP requires us to recognize a valuation allowance unless it is “more likely than not” that we could realize the benefit of the NOL carryforwards and deferred tax assets in future periods. Having returned to profitability in 2005, we now expect that earnings performance should allow us to benefit from the NOL carryforwards, and therefore, the previously recorded valuation allowance is no longer required. The valuation allowance and net deferred tax asset benefit was $71.5 million resulting from the reversal of the previously established valuation allowance of $56.0 million and net deferred tax assets and tax benefit from tax return filings. The reduction in foreign taxes, net of federal benefit, in 2005 from 2004 relates to a federal tax deduction on actual foreign cash taxes paid versus accrued foreign taxes. The increase in income tax on foreign corporate income in 2005 is due to the increase in earnings on our foreign corporations and the related recognition of U.S. taxes on the earnings. 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.”

RESULTS OF OPERATIONS (continued)

Analysis of Discontinued Operations


	Year Ended December 31,
	2005			2004
	(Dollars in Thousands)

U.S. jackup and platform drilling revenues	$	193		$	34,350

U.S. jackup and platform drilling gross margin	$	100		$	7,720
Loss on disposition of assets, net of gains and impairments		(29	)		(4,238	)

Income from discontinued operations	$	71		$	3,482

In August 2004, we finalized the sale of five jackup and four platform rigs, realizing net proceeds of $39.3 million. No gain or loss was recorded on the sale and the proceeds were used to pay down debt. The last jackup rig was sold on January 3, 2005. With the consummation of this transaction, all of our jackup and platform rigs have been sold. No other assets remain related to our discontinued operations and all proceeds were used to pay down debt. Discontinued operations results for 2005 include the results of operating the last jackup rig in the first week of 2005, and 2004 results include the results of the jackup and platform rigs sold in August 2004 through their sale date, and the last jackup rig sold in 2005 for the entire year of 2004.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

We recorded a net loss of $47.1 million for the year ended December 31, 2004 as compared to a net loss of $109.7 million for the year ended December 31, 2003. The loss from continuing operations was $50.6 million and $52.4 million for the years ended December 31, 2004 and 2003, respectively. The income (loss) from discontinued operations was $3.5 million and ($57.3) million for 2004 and 2003, respectively. An impairment of $53.8 million is included in 2003 discontinued operations related primarily to the sale of U.S. jackup and platform rigs that was completed in 2004, except for jackup rig 25 which was sold in January 2005.

RESULTS OF OPERATIONS (continued)

Revenues increased $37.9 million to $376.5 million in 2004 as compared to 2003. The increase is attributed to higher utilization in the U.S. barge operations, international land operations and our rental tools operations, Quail Tools.


	Year Ended December 31,
	2004					2003
	(Dollars in Thousands)

Drilling and rental revenues:
U.S. drilling	$	88,512		23	%	$	67,449		20	%
International drilling		220,846		59	%		216,567		64	%
Rental tools		67,167		18	%		54,637		16	%

Total drilling and rental revenues	$	376,525		100	%	$	338,653		100	%

Drilling and rental operating income:
U.S. drilling gross margin (1)	$	34,386		39	%	$	19,709		29	%
International drilling gross margin (1)		52,395		24	%		64,366		30	%
Rental tools gross margin (1)		39,130		58	%		31,586		58	%
Depreciation and amortization		(69,241	)				(73,679	)

Total drilling and rental operating income (2)		56,670					41,982
Net construction contract operating income		—					2,000
General and administrative expense		(23,413	)				(19,256	)
Provision for reduction in carrying value of certain assets		(13,120	)				(6,028	)
Gain on disposition of assets, net		3,730					4,229

Total operating income	$	23,867				$	22,927


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

Year Ended December 31, 2004	(Dollars in Thousands)
Drilling and rental operating income (2)	$	15,938		$	15,858	$	24,874
Depreciation and amortization		18,448			36,537		14,256

Drilling and rental gross margin	$	34,386		$	52,395	$	39,130

Year Ended December 31, 2003
Drilling and rental operating income (loss) (2)	$	(186	)	$	24,557	$	17,611
Depreciation and amortization		19,895			39,809		13,975

Drilling and rental gross margin	$	19,709		$	64,366	$	31,586


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

U.S. Drilling Segment

U.S. drilling revenues increased $21.1 million in 2004 to $88.5 million, due to higher utilization and dayrates. During the fourth quarter of 2004, we impaired two workover barge rigs and removed them from the marketable rig fleet. Also during the second quarter of 2004, we moved deep drilling barge rig 53 to Mexico to begin work on a two-year contract for Petroleos Mexicanos S.A. (“Pemex”). Average 2004 utilization for the barge rigs increased to

RESULTS OF OPERATIONS (continued)

U.S. Drilling Segment (continued)

63 percent from an average utilization during 2003 of 50 percent. The increase in utilization accounted for approximately $10.8 million of the increase in revenues. Average 2004 dayrates increased approximately $2,200 per day as compared to 2003 accounting for the remaining $10.2 million of the revenues increase. During the third quarter of 2004, we upgraded barge rig 76 enabling it to drill effectively in ultra-deep shelf drilling. The rig began drilling under a multi-well program in late October at a significantly higher dayrate of approximately $37,000 per day, compared to the previous dayrate of approximately $21,000 per day. As a result of higher dayrates and utilization, gross margins in the U.S. drilling segment increased $14.7 million to $34.4 million. Gross margins during the fourth quarter of 2004 were negatively impacted by $1.5 million for the move of barge rig 72 from Nigeria to the U.S. Gulf of Mexico.

International Drilling Segment

International drilling revenues increased $4.3 million to $220.8 million in 2004 as compared to 2003. International land drilling revenues increased $48.7 million to $188.0 million offset by a reduction in international offshore drilling revenues of $44.4 million to $32.8 million. International drilling gross margins decreased by $12.0 million to $52.4 million due almost entirely to reduced activity in the international offshore barge rigs.

International land drilling utilization increased in all regions except the Latin America countries of Colombia, Bolivia and Peru. During the second and third quarters of 2004, we moved seven land rigs which had been located in Colombia, Bolivia and Argentina to Mexico to begin a two-year drilling contract for Halliburton contributing $19.8 million in revenues. In our Asia Pacific region, revenues increased by $14.0 million as a result of new drilling contracts in Bangladesh, New Zealand and Papua New Guinea when compared to 2003. In our CIS region, revenues increased by $25.6 million due to adding a second rig in Turkmenistan in March of 2004 and from the full year impact of our five-year O&M contract on Sakhalin Island. The Sakhalin Island contract commenced operations in June 2003. Rig 236 which had been operating in northern Russia completed its drilling activities in June 2004 and was stacked for the remainder of the year. Utilization in Colombia, Bolivia and Peru decreased significantly during most of 2004, resulting in $10.3 million less revenues when compared to 2003. In Peru, rig 228 was placed on standby at the request of the customer in April 2004 and received a reduced standby rate for the remainder of 2004. All of the rigs in Peru were sold in 2005. In Bolivia no rigs worked during 2004. Because we did not anticipate any change in this market for the foreseeable future, we closed the operation and recognized a $2.4 million impairment charge during the fourth quarter of 2004, reducing the net carrying value of the Bolivia assets to net realizable value. Three land rigs remained in Colombia as of the end of 2004, but were sold in 2005.

International land gross margins increased $16.0 million in 2004 when compared to 2003. The increase was primarily the result of increased activity as noted above in the CIS and Asia Pacific regions. In addition, gross margins increased in the last half of 2004 as our seven land rigs began operations in Mexico. In 2004 when compared to 2003, international land gross margins were negatively impacted by a $4.0 million decrease in Latin America operations, excluding Mexico. The decrease was primarily attributed to the standby situation in Peru and the reduced activity in Colombia.

International offshore drilling revenues decreased $44.4 million to $32.8 million in 2004 as compared to 2003. The decrease in revenues was attributable to a $24.6 million decrease in the Caspian Sea operation and a $24.8 million decrease in our Nigeria operations, partially offset by increased revenues of $5.0 million from our barge rig in Mexico. In November 2003, our arctic-class barge rig 257 completed its initial four-year contract and was demobilized and stacked throughout most of 2004. During the fourth quarter of 2004, we signed a two-well contract with options for an additional four wells. Barge rig 257 began recognizing revenues under this new contract in late December 2004. In Nigeria, revenues decreased significantly due to reduced utilization. Barge rig 75 worked throughout 2003 but returned to port for repairs in June 2004 and its initial five-year contract expired mid-September 2004. A three-year contract extension was signed in September 2004 at a dayrate approximately 15 percent less than the initial five-year term. Barge rig 73 operated the first five months of 2004 and was stacked until mid-December 2004. In mid-December, barge rig 73 began mobilizing under a new two-year contract with a one-year option. Barge rig 74 remained evacuated since sustaining substantial damage due to community unrest in March 2003. In December 2004, we received insurance proceeds in the amount of $18.5 million, a portion of which was used in

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

February 2005 to reduce long-term debt. During the fourth quarter of 2004, barge rig 72 began its move from Nigeria to the U.S. Gulf of Mexico region.

International offshore gross margins decreased $27.9 million in 2004 as compared to 2003. Costs to maintain barge rig 257 in a stacked condition approximated $1.0 million per quarter and we also settled an assessment of duties, taxes and penalties for barge rig 257 with the Customs Control in Mangistau, Kazakhstan, in the third quarter of 2004 for $2.1 million, resulting in a negative gross margin of $6.2 million. In Nigeria, lower utilization on the barge rigs caused reduced revenues in 2004. Ongoing costs to maintain the barges in stacked condition and increased insurance cost caused by losses incurred, both negatively impacted gross margins. In addition, Nigerian tax authorities assessed additional VAT, resulting in a charge of $2.3 million in the second quarter of 2004. All of these factors combined to reduce the $11.7 million 2003 gross margin in Nigeria to breakeven in 2004. Barge rig 53 commenced operations in Mexico in May 2004 under a new two-year contract for Pemex. Prior to receiving this contract, the barge rig had operated in the U.S. Gulf of Mexico.

Rental Tools Segment

Rental tools revenues increased $12.5 million to $67.2 million in 2004. The increases in revenues were attributable to a $2.5 million increase from the New Iberia, Louisiana facility, $3.0 million from the Victoria, Texas facility, $4.8 million from the Odessa, Texas facility and $2.2 million from the Evanston, Wyoming facility. Both the New Iberia, Louisiana and Victoria, Texas operations experienced an increase in customer demand due to increased deep water drilling in the Gulf of Mexico. All locations experienced increased customer demand and saw an expansion in customer base.

Other Financial Data

Depreciation and amortization expense decreased $4.4 million to $69.2 million in 2004. The decrease is primarily attributable to limits on our capital expenditure program that were enacted until our debt reduction goal was met.

General and administrative expense increased $4.2 million to $23.4 million for the year ended December 31, 2004 as compared to 2003. During the first quarter of 2004 we incurred an expense of $1.0 million related to the accelerated vesting of certain restricted stock including our portion of the FICA expense. The restricted shares were granted in July 2003 and were scheduled to vest over seven years, but included an accelerated vesting feature based on stock performance goals. In accordance with the accelerated vesting feature, 377,500 shares of the grant vested in March 2004 based on meeting the initial stock performance goal of $3.50 per share for 30 consecutive days. The remaining 340,000 shares vested in March 2005 after the closing stock price of $5.00 per share was met for 30 consecutive days which resulted in an expense of $0.7 million. This expense was recognized during the first quarter of 2005. In the second quarter of 2004, we expensed $1.4 million related to severance costs associated with our former chief operating officer. In addition, during 2004, we incurred approximately $2.7 million related to the documentation and testing for compliance with section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”).

During 2004, we recognized a provision for reduction in carrying value of certain assets of $13.1 million. During the fourth quarter of 2004, we determined that two workover barge rigs in the U.S. Gulf of Mexico fleet were not economically marketable. As a result, we recorded an impairment of $3.2 million. In the Asia Pacific region, we reduced the carrying amount of two rigs to net realizable value, which resulted in recording an impairment charge of $0.7 million.

Also, during the fourth quarter of 2004, we made the decision to dispose of all the assets in Bolivia, which included two land rigs, inventory and spare parts. We incurred an impairment charge of $2.4 million to reduce the cost basis of these assets to net realizable value. We closed the Bolivia office in the second quarter of 2005. During the second quarter of 2004, we reclassified our Latin America assets from discontinued operations to continuing operations and recognized a $5.1 million charge to adjust the value of the Latin America assets to their fair value. In accordance with GAAP, the $5.1 million represents the depreciation that would have been recognized had the assets been continuously classified as held and used. In addition, during 2004 we reserved $1.7 million for an asset representing premiums paid in prior years on two split dollar life insurance policies for Robert L. Parker. The value

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

of the asset was reduced to the cash surrender value of the insurance policies. See Note 13 in the notes to the consolidated financial statements.

In 2003 three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia, Louisiana were impaired by $2.6 million to estimated salvage value. Subsequent to December 31, 2003, we signed an agreement to sell the New Iberia, Louisiana land and buildings for a net sales price of $6.4 million. This resulted in an impairment of $3.4 million at December 31, 2003, as the net book value of the property exceeded the net sales price. The transaction closed in August 2004 and no additional gain or loss was recognized upon disposition.

Interest expense decreased $3.4 million to $50.4 million for the year ended December 31, 2004 as compared to 2003. The decrease in interest expense is primarily attributable to the net reduction of $90.2 million to our outstanding debt balance in 2004. The majority of the debt reduction occurred in August 2004 with proceeds from the sale of our jackup and platform rigs.

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 are reporting the mark-to-market change in the fair value of the interest rate derivatives currently in earnings. For the year ended December 31, 2004, we recognized a non-cash charge for a decrease in the fair value of the derivative positions of $0.8 million.

On September 2, 2004, we issued $150.0 million of Senior Floating Rate Notes and concurrently repurchased $80.0 million of our 10.125% Senior Notes at a premium and paid off $70.0 million of our delay draw term loan. Total charges of $8.8 million consisting of the 6.54 percent tender offer, including a two percent premium on the repurchase of the 10.125% Senior Notes, the write-off of the previously capitalized debt issuance costs associated with the repurchase of the 10.125% Senior Notes and the repayment of the delay draw term loan, and legal and other fees were recorded as loss on extinguishment of debt in the consolidated statement of operations. In 2003, in conjunction with the refinancing of a portion of our debt, we incurred $5.3 million expense related to the retirement of our 9.75% Senior Notes. These costs have been recorded as loss on extinguishment of debt and include costs of the call premium on the 9.75% Senior Notes and write-off of remaining capitalized debt issuance costs offset by the write-off of the remaining swap gain that was being amortized over the remaining life of the 9.75% Senior Notes.

We have a 50 percent interest in a joint venture in Kazakhstan, AralParker, which owns and operates two drilling rigs and other drilling equipment. AralParker is included in the consolidated financial statements of Parker Drilling Company. During 2004, we recognized an expense for minority interest of $1.1 million and in 2003, income from minority interest of $0.5 million.

Income tax expense from continuing operations consists of foreign tax expense of $15.0 million for the year ended December 31, 2004. For the year ended December 31, 2003, income tax expense from continuing operations consisted of foreign tax expense of $17.0 million. Foreign taxes decreased $2.0 million in 2004 due primarily to reduced activity in Nigeria in addition to barge rig 257 in Kazakhstan being stacked the majority of the year. Partially offsetting these reductions were increased taxes in Papua New Guinea related to 2004 and 2003 assessments and the startup of operations in Mexico. Although we incurred a net loss in 2004, no additional deferred tax benefit was recognized since the sum of our deferred tax assets, principally the net operating loss carryforwards, exceeded the deferred tax liabilities, principally the excess of tax depreciation over book depreciation. This additional deferred tax asset was fully reserved through a valuation allowance in both 2004 and 2003.

RESULTS OF OPERATIONS (continued)

Analysis of Discontinued Operations


	Year Ended December 31,
	2004			2003
	(Dollars in Thousands)

U.S. jackup and platform drilling revenues	$	34,350		$	47,239

U.S. jackup and platform drilling gross margin (1)	$	7,720		$	6,320
Depreciation and amortization (2)		—			(9,817	)
Loss on disposition of assets, net of gains and impairments		(4,238	)		(53,768	)

Income (loss) from discontinued operations	$	3,482		$	(57,265	)


(1)		Drilling gross margin is computed as drilling revenues less direct drilling operating expenses, excluding depreciation and amortization expense. The gross margin amounts and gross margin percentages should not be used as a substitute for those amounts reported under GAAP. However, we monitor our business segments based on several criteria, including drilling gross margin. Management believes that this information is useful to our investors because it more closely tracks cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:


	Year Ended December 31,
	2004		2003
	(Dollars in Thousands)

U.S. jackup and platform drilling operating income (loss)	$	7,720	$	(3,497	)
Depreciation and amortization		—		9,817

Drilling gross margin	$	7,720	$	6,320


(2)		Depreciation and amortization — in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we stopped recording depreciation expense related to the discontinued operations effective June 30, 2003.

On August 2, 2004, we finalized the sale of five jackup and four platform rigs, realizing net proceeds of $39.3 million. No gain or loss was recorded on the sale and the proceeds were used to pay down debt. Jackup rig 25 was excluded from this sale, although the purchaser retained the exclusive right to purchase it. On January 3, 2005, we sold jackup rig 25 to such purchaser. We received proceeds of $21.5 million and recognized an additional impairment on the disposition of $4.1 million in December 2004. With the consummation 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 our discontinued operations and all proceeds were used to pay down debt.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

As of December 31, 2005, we had cash and cash equivalents of $60.2 million, an increase of $15.9 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 reduction in debt of $101.0 million, which is further detailed in subsequent paragraphs.

As of December 31, 2004, we had cash and cash equivalents of $44.3 million, a decrease of $23.5 million from December 31, 2003. The primary sources of cash for the twelve-month period as reflected on the consolidated statement of cash flows were $28.8 million provided by operating activities, $41.6 million of insurance proceeds, and $52.4 million of proceeds from the disposition of assets and marketable securities. The primary uses of cash for the twelve-month period ended December 31, 2004 were $47.3 million for capital expenditures and $99.0 million for financing activities. Major capital expenditures for the period included $11.9 million to refurbish rigs for work in Mexico, $7.5 million to refurbish barge rig 76 for ultra-deep drilling in the shallow waters of the U.S. Gulf of Mexico and $13.0 million for tubulars and other rental tools for Quail Tools. Our financing activities include a net reduction in debt of $90.2 million and are further detailed in subsequent paragraphs.

As of December 31, 2003, we had cash and cash equivalents of $67.8 million, an increase of $15.8 million from December 31, 2002. The primary sources of cash for the twelve-month period as reflected on the consolidated statement of cash flows were $62.5 million provided by operating activities, $6.0 million of insurance proceeds for barge rig 18 and $6.3 million of proceeds from the disposition of equipment. The primary uses of cash for the twelve month period ended December 31, 2003 were $35.0 million for capital expenditures and $15.2 million reduction of debt. Major capital expenditures during 2003 included $18.1 million for Quail Tools (consisting mostly of purchases of drill pipe and tubulars) and $2.1 million to refurbish rig 230 and rig 247 for work in Turkmenistan. The major components of our net debt reduction were the purchases of $19.3 million face value of our outstanding 5.5% Convertible Subordinated Notes on the open market, $14.8 million in May 2003 and $4.5 million in December 2003. In addition, we paid down $5.5 million of a secured promissory note to Boeing Capital Corporation. During the fourth quarter of 2003 we paid off all of our outstanding 9.75% Senior Notes ($214.2 million face value) with proceeds from our new 9.625% Senior Notes ($175.0 million face value) and a $50.0 million initial draw of a $100.0 million term loan.

Financing Activity

Our current $40.0 million 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. Availability under the revolving credit facility is subject to a borrowing base limitation based on 85 percent of eligible receivables plus a value for eligible rental tools equipment. The credit facility calls for a borrowing base calculation only when the credit facility has outstanding loans, including letters of credit, totaling at least $25.0 million. As of December 31, 2005, there were $10.3 million in letters of credit outstanding and no loans. Subsequent to December 31, 2005, an amendment was signed to eliminate the $25.0 million limit for letters of credit and to give us the ability to call outstanding Senior Notes and Senior Floating Rate Notes without a limitation concerning commitments, including letters of credit, under the credit agreement. A copy of the amendment is filed as an exhibit to this Form 10-K.

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.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (continued)

On the same date that we issued the additional $50.0 million of 9.625% Senior Notes (April 21, 2005), we issued a redemption notice for $65.0 million of our 10.125% Senior Notes at the redemption price of 105.0625 percent. The redemption date was May 21, 2005, and was funded by the net proceeds from the issuance of the additional 9.625% Senior Notes and cash on hand.

On June 16, 2005, we issued a redemption notice to retire $30.0 million of our 10.125% Senior Notes at the redemption price of 105.0625 percent. The redemption date was July 16, 2005 and 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.

We had total long-term debt of $380.0 million as of December 31, 2005. The long-term debt included:


	•	$150.0 million aggregate principal amount of Senior Floating Rate Notes bearing interest at a rate of LIBOR plus 4.75%, which are due September 1, 2010; and

	•	$225.0 million aggregate principal amount of 9.625% Senior Notes, which are due October 1, 2013 plus the associated $5.0 million in unamortized debt premium.

As of December 31, 2005, we had approximately $89.9 million of liquidity. This liquidity was comprised of $60.2 million of cash and cash equivalents on hand and $29.7 million of availability under the revolving credit facility.

The following table summarizes our future contractual cash obligations:


			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)	$	375,000	$	—	$	—	$	150,000	$	225,000
Long-term debt — interest (1)		229,600		34,891		69,783		65,371		59,555
Operating leases (2)		13,250		5,166		5,055		2,078		951
Purchase commitments (3)		30,279		30,279		—		—		—

Total contractual obligations	$	648,129	$	70,336	$	74,838	$	217,449	$	285,506

Commercial commitments:
Revolving credit facility (4)	$	—	$	—	$	—	$	—	$	—
Standby letters of credit (4)		10,258		10,258		—		—		—

Total commercial commitments (5)	$	10,258	$	10,258	$	—	$	—	$	—


(1)		Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes but the remaining unamortized premium of $5.0 million is not included in the contractual cash obligations schedule. A portion of the interest on the Senior Floating Rate Notes has been fixed through variable-to-fixed interest rate swap agreements. The issuer (Bank of America, N.A.) of each swap has the option to extend each swap for an additional two years at the termination of the initial swap period. For the purpose of this table, the highest interest rate currently hedged is used in calculating the interest on future floating rate periods.

(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, 2005, related to rig upgrade projects and new rig construction.

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (continued)


(4)		We have a $40.0 million revolving credit facility. As of December 31, 2005 no amounts have been drawn down, but $10.3 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $29.7 million availability. The revolving credit facility expires in December 2007.

(5)		We have entered into employment agreements with the executive officers of the Company; see Note 12 in the notes to the consolidated financial statements.

We do not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.

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. 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 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.

We recorded impairments to our long-lived assets of $4.9 million, $13.1 million and $6.0 million in 2005, 2004, and 2003, respectively. We also recorded $9.4 million of impairments to our discontinued operations assets in 2004.

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.

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

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 analysis of goodwill at each year end. Our annual impairment tests of goodwill at years ending 2003, 2004 and 2005 indicated that the fair value of operations to which goodwill relates exceeded the carrying values as of December 31, 2003, 2004 and 2005; 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.

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

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

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. As a result of our expected earnings performance which should allow us to benefit from the NOL carryforwards, we have concluded that no valuation allowance is currently required. We will reevaluate our ability to utilize our NOL carryforwards in future periods and, in compliance with SFAS No. 109 “Accounting for Income Taxes,” we will record any resulting adjustments that may be required to deferred income tax expense.

We have provided for U.S. deferred taxes on the unremitted earnings of our U.S. and foreign subsidiaries as the earnings are not permanently reinvested.

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, if significant, are deferred and amortized over the term of the related drilling contract.

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 No. 133 established accounting and disclosure requirements for most derivative instruments and hedge transactions involving derivatives. SFAS No. 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 interest rate swap agreements provide us with interest rate protection on the Senior Floating Rate Notes due 2010.

We do 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 is caused by embedded written call options in the interest rate swap agreements that do not exist in the notes. Accordingly, we recognize the volatility of the swap agreements on a mark-to-market basis in our consolidated statement of operations. For the year ended December 31, 2005, we recognized a non-cash increase in the fair value of the interest rate derivatives of $2.1 million. For the year ended December 31, 2004, we recognized a non-cash decrease in the fair value of $0.8 million. These non-cash expenses are reported in the consolidated statement of operations as “Changes in fair value of derivative positions.” The non-cash increase in fair value in 2005 is reported in the consolidated balance sheet as “Other assets,” and the non-cash decrease in fair value in 2004 is reported in “Other long-term liabilities.” For additional information see Note 6 in the notes to the consolidated financial statements.

The fair market value adjustment of these swap agreements will generally fluctuate based on the implied forward interest rate curve for the three-month LIBOR. If the implied forward interest rate curve decreases, the fair market value of the interest swap agreements will decrease and we will record an additional charge. If the implied forward interest rate curve increases, the fair market value of the interest swap agreements will increase, and we will record income. We analyze the position of the swap agreements on a quarterly basis and record the mark-to-market impact based on the analysis.

Recent Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN No. 47 requires companies to record a liability for those asset retirement obligations in which the timing and/or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS No. 143, “Accounting for Asset Retirement Obligations,” which we adopted on January 1, 2003. FIN No. 47, which was adopted October 1, 2005, requires us to accrue a liability when a range of scenarios indicates that the potential timing and/or settlement amounts of our

OTHER MATTERS (continued)

Recent Accounting Pronouncements (continued)

conditional asset retirement obligations can be determined. This pronouncement did not have any impact on our consolidated financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by this statement. We will adopt this standard effective January 1, 2006 and we do not expect any impact on our consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the SEC approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to state that the provisions of SFAS No. 123R are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this standard until the first quarter of 2006. Our plans are to use the modified prospective application method as detailed in SFAS No. 123R. We expect the impact on our consolidated financial statements to be consistent with the impact disclosed in Note 1 of the notes to the consolidated financial statements. Our future cash flows will not be impacted by the adoption of this standard. See “Stock-Based Compensation” within Note 1 of the notes to the consolidated financial statements for further information.

In October 2005, the FASB issued FASB Staff Position (“FSP”) SFAS 123R-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123R.” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123R. The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the Company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with its corporate governance requirements as long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with our adoption of SFAS No. 123R.

In November 2005, the FASB issued FSP SFAS No. 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” in response to issues financial statement preparers raised about the ability to calculate estimated tax benefit amounts that would have qualified if the entity had adopted SFAS No. 123 for recognition purposes in 1995 as opposed to opting for the disclosure of the pro forma effects. The position provides for a transition method that provides a proscribed computation for the estimated beginning balance of the related additional paid in capital pool and a simplified method to determine the subsequent impact on the pool relating to employee option awards that are fully vested and outstanding upon adoption of SFAS No. 123R. We are currently evaluating the impact of this position on our calculation upon adoption of SFAS No. 123R in 2006.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140,” to clarify accounting for derivative instruments that are hybrid financial instruments with embedded derivatives, contain interest or principal only strips and for freestanding derivatives; further define embedded derivatives and clarify derivative-related restrictions on special purpose entities. This standard is effective for fiscal periods beginning after September 16, 2006 and should not have any impact on our consolidated financial statements.


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

Interest Rate Risk

We 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, 2005 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, 2005 and terminating September 4, 2007. In each case, an option to extend each swap for an additional two years at the same rates was given to the issuer, Bank of America, N.A. A 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 the six-month period beginning March 1, 2005 and to extend $50.0 million at a fixed interest rate of 7.60% for the 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.

These swap agreements do not meet the hedge criteria in SFAS No. 133 and are, therefore, not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized currently in “Change in fair value of derivative positions” on the consolidated statement of operations. As of December 31, 2005, we had the following derivative instruments outstanding related to our interest rate swaps:


				Notional			Fixed			Fair
Effective Date		Termination Date		Amount		Floating Rate	Rate			Value
(Dollars in Thousands)

	September 1, 2005		September 2, 2008	$	50,000	Three-month LIBOR plus 475 basis points		8.83	%	$	553
	September 1, 2005		September 4, 2007	$	50,000	Three-month LIBOR plus 475 basis points		8.48	%		728


										$	1,281

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 $251.2 million at December 31, 2005. Our $150.0 million principal amount of Senior Floating Rate Notes due 2010 estimated fair value was $154.3 million and $155.4 million on December 31, 2005 and December 31, 2004, respectively. The estimated fair value of our $175.0 million principal amount of 9.625% Senior Notes due 2013, based on quoted market prices was $196.4 million at December 31, 2004.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Parker Drilling Company

We have completed integrated audits of Parker Drilling Company’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Parker Drilling Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible 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 opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable

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


	Year Ended December 31,
	2005			2004			2003

Drilling and rental revenues:
U.S. drilling	$	128,252		$	88,512		$	67,449
International drilling		308,572			220,846			216,567
Rental tools		94,838			67,167			54,637

Total drilling and rental revenues		531,662			376,525			338,653

Drilling and rental operating expenses:
U.S. drilling		66,827			54,126			47,740
International drilling		237,161			168,451			152,201
Rental tools		38,211			28,037			23,051
Depreciation and amortization		67,204			69,241			73,679

Total drilling and rental operating expenses		409,403			319,855			296,671

Drilling and rental operating income		122,259			56,670			41,982

Construction contract revenue		—			—			7,030
Construction contract expense		—			—			5,030

Construction contract operating income		—			—			2,000

General and administration expense		(27,830	)		(23,413	)		(19,256	)
Provision for reduction in carrying value of certain assets		(4,884	)		(13,120	)		(6,028	)
Gain on disposition of assets, net		25,578			3,730			4,229

Total operating income		115,123			23,867			22,927

Other income and (expense):
Interest expense		(42,113	)		(50,368	)		(53,790	)
Change in fair value of derivative positions		2,076			(794	)		—
Interest income		2,241			816			1,013
Loss on extinguishment of debt		(8,241	)		(8,753	)		(5,274	)
Minority interest		1,905			(1,143	)		464
Other		(763	)		819			(789	)

Total other income and (expense)		(44,895	)		(59,423	)		(58,376	)

Income (loss) before income taxes		70,228			(35,556	)		(35,449	)

Income tax expense (benefit):
Current tax expense		16,328			15,009			16,985
Deferred tax benefit		(44,912	)		—			—

Total income tax expense (benefit)		(28,584	)		15,009			16,985

Income (loss) from continuing operations		98,812			(50,565	)		(52,434	)
Discontinued operations		71			3,482			(57,265	)

Net income (loss)	$	98,883		$	(47,083	)	$	(109,699	)

Basic earnings (loss) per share:
Income (loss) from continuing operations	$	1.03		$	(0.54	)	$	(0.56	)
Discontinued operations	$	—		$	0.04		$	(0.61	)
Net income (loss)	$	1.03		$	(0.50	)	$	(1.17	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	1.02		$	(0.54	)	$	(0.56	)
Discontinued operations	$	—		$	0.04		$	(0.61	)
Net income (loss)	$	1.02		$	(0.50	)	$	(1.17	)
Number of common shares used in computing earnings per share:
Basic		95,818,893			94,113,257			93,420,713
Diluted		97,208,345			94,113,257			93,420,713

See accompanying notes to the consolidated financial statements.

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


	December 31,
ASSETS	2005		2004

Current assets:
Cash and cash equivalents	$	60,176	$	44,267
Marketable securities		18,000		—
Accounts and notes receivable, net of allowance for bad debts of $1,639 in 2005 and $3,591 in 2004		104,681		99,315
Rig materials and supplies		18,179		19,206
Deferred costs		4,223		13,546
Deferred income taxes		12,018		3,894
Other current assets		64,058		5,924

Total current assets		281,335		186,152

Property, plant and equipment, at cost:
Drilling equipment		750,368		839,977
Rental tools		119,028		100,101
Buildings, land and improvements		17,448		16,418
Other		31,528		31,756
Construction in progress		23,193		5,057

		941,565		993,309
Less accumulated depreciation and amortization		586,168		610,485

Property, plant and equipment, net		355,397		382,824
Assets held for sale		—		23,665
Other assets:
Goodwill		107,606		107,606
Rig materials and supplies		2,819		3,198
Debt issuance costs		8,088		10,896
Deferred income taxes		34,449		—
Other assets		11,926		12,249

Total other assets		164,888		133,949

Total assets	$	801,620	$	726,590

See accompanying notes to the consolidated financial statements.

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


	December 31,
LIABILITIES AND STOCKHOLDERS’ EQUITY	2005			2004

Current liabilities:
Current portion of long-term debt	$	—		$	24
Accounts payable		31,909			22,105
Accrued liabilities		109,068			50,520
Accrued income taxes		9,778			14,704

Total current liabilities		150,755			87,353

Long-term debt		380,015			481,039
Other long-term liabilities		11,021			9,281
Commitments and contingencies (Note 12)		—			—
Stockholders’ equity:
Preferred stock, $1 par value, 1,942,000 shares authorized, no shares outstanding		—			—
Common stock, $0.162/3 par value, authorized 140,000,000 shares, issued and outstanding 97,836,254 shares (94,999,249 shares in 2004)		16,306			15,833
Capital in excess of par value		456,135			441,085
Unamortized restricted stock plan compensation		(4,212	)		(718	)
Accumulated deficit		(208,400	)		(307,283	)

Total stockholders’ equity		259,829			148,917

Total liabilities and stockholders’ equity	$	801,620		$	726,590

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,
	2005			2004			2003

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	98,883		$	(47,083	)	$	(109,699	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		67,204			69,241			83,496
Amortization of debt issuance and premium		958			1,924			1,837
Loss on extinguishment of debt		935			2,657			1,161
Gain on disposition of assets		(25,549	)		(3,620	)		(4,229	)
Gain on disposition of marketable securities		—			(762	)		—
Provision for reduction in carrying value of certain assets		4,884			17,248			59,796
Deferred tax benefit		(44,912	)		—			—
Other		2,913			6,132			3,563
Change in assets and liabilities:
Accounts and notes receivable		(568	)		(10,565	)		(107	)
Rig materials and supplies		(3,179	)		361			(1,120	)
Other current assets		7,589			(30,735	)		6,373
Accounts payable and accrued liabilities		18,218			12,749			9,173
Accrued income taxes		(5,100	)		895			9,462
Other assets		331			10,360			2,748

Net cash provided by operating activities		122,607			28,802			62,454

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(69,492	)		(47,318	)		(34,962	)
Proceeds from the sale of assets		61,046			51,053			6,337
Proceeds from insurance claims		13,850			41,566			6,000
Purchase of marketable securities		(18,000	)		—			—
Proceeds from sale of marketable securities		—			1,377			—

Net cash provided by (used in) investing activities	$	(12,596	)	$	46,678		$	(22,625	)

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,
	2005			2004			2003

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	$	55,500		$	200,000		$	225,000
Principal payments under debt obligations		(155,632	)		(290,206	)		(240,308	)
Payment of debt issuance costs		(655	)		(10,243	)		(8,738	)
Proceeds from stock options exercised		6,685			1,471			—

Net cash used in financing activities		(94,102	)		(98,978	)		(24,046	)

Net increase (decrease) in cash and cash equivalents		15,909			(23,498	)		15,783
Cash and cash equivalents at beginning of year		44,267			67,765			51,982

Cash and cash equivalents at end of year	$	60,176		$	44,267		$	67,765


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	41,308		$	49,181		$	52,894
Income taxes	$	13,415		$	15,062		$	15,741
Discontinued operations:
Depreciation	$	—		$	—		$	9,817
Loss on disposition of assets	$	29		$	110		$	—
Provision for reduction in carrying value of certain assets	$	—		$	4,128		$	53,768

Supplemental noncash investing and financing activity:
Net unrealized gain on investments available for sale	$	—		$	—		$	217
Capital lease obligation	$	—		$	—		$	290

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, 2002		92,793	$	15,465	$	434,998	$	—		$	664		$	(150,501	)
Activity in employees’ stock plans		1,383		231		3,313		(2,031	)		—			—
Amortization of restricted stock plan compensation		—		—		—		146			—			—
Other comprehensive income — net unrealized gain on investments (net of taxes of $0)		—		—		—		—			217			—
Net loss (total comprehensive loss of $109,482)		—		—		—		—			—			(109,699	)

Balances, December 31, 2003		94,176		15,696		438,311		(1,885	)		881			(260,200	)
Activity in employees’ stock plans		823		137		2,774		—			—			—
Amortization of restricted stock plan compensation		—		—		—		1,167			—			—
Other comprehensive loss — net unrealized loss on investments (net of taxes of $0)		—		—		—		—			(881	)		—
Net loss (total comprehensive loss of $47,964)		—		—		—		—			—			(47,083	)

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 net income of $98,883)		—		—		—		—			—			98,883

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

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 two companies in which subsidiaries of Parker Drilling have a 50 percent stock ownership but exert control over the entities’ operations (collectively, the “Company”). A subsidiary of Parker Drilling also has a 50 percent interest in another company, which is accounted for under the equity method as the Company’s interest in the entity does not meet the consolidation criteria described above.

Operations — The Company provides land and offshore contract drilling services and rental tools on a worldwide basis to major, independent and national oil and gas companies and integrated service providers. At December 31, 2005, the Company’s marketable rig fleet consists of 23 barge drilling and workover rigs, and 24 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 services that are ancillary to its principal drilling services, including engineering and logistics, as well as 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, if significant, are deferred and amortized over the term of the related drilling contract.

Construction Contract — The Company has historically only constructed drilling rigs for its own use. At the request of one of its significant customers, the Company entered into a contract to design, construct, mobilize and sell (“construction contract”) a specialized drilling rig to drill extended-reach wells to offshore targets from a land-based location on Sakhalin Island, Russia, for an international consortium of oil and gas companies. Subsequently, the Company entered into a contract to operate the rig on behalf of the consortium. Generally Accepted Accounting Principles (“GAAP”) requires that revenues received and costs incurred related to the construction contract be accounted for and reported on a gross basis and income for the related fees recognized on a percentage-of-completion basis. Because this construction contract is not a part of the Company’s historical or normal operations, the revenues and costs related to this contract have been shown as a separate component in the statement of operations. This contract was completed during 2003.

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 $41.3 million, $26.0 million and $24.3 million during the years ended December 31, 2005, 2004 and 2003.

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 has marketable securities that consist of variable rate auction rate securities and are classified as available for sale. The investments are carried at par value. While the final maturities of these auction rate securities are December 2037 and September 2043, the Company’s investments mature and are reinvested every seven and 28 days.

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 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 with respect to their inability to make payments. 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 feels 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,
	2005			2004
	(Dollars in Thousands)

Trade	$	105,982		$	102,765
Employee (1)		338			141
Allowance for doubtful accounts (2)		(1,639	)		(3,591	)

Total receivables	$	104,681		$	99,315


(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, 2005, 2004 and 2003 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 properties 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.

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 in the notes to the consolidated financial statements for additional details regarding goodwill.

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 $3.4 million and $6.5 million at December 31, 2005 and 2004, 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 is the accrual of workers’ compensation liability, deferred tax liability and deferred mobilization revenue which is not expected to be paid or recognized within the next year.

Income Taxes — Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are recognized against deferred tax assets unless it is “more likely than not” that the Company can realize the benefit of the net operating loss (“NOL”) carryforwards and deferred tax assets in future periods.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

Earnings (Loss) Per Share (“EPS”) — Basic earnings (loss) per share is computed by dividing net income (loss), 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, 2005 and 2004, the Company had deposits in domestic banks in excess of federally insured limits of approximately $68.1 million and $43.7 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2005 and 2004 of $10.2 million and $11.1 million, respectively, which are not federally insured.

The Company’s customer base consists of major, independent and national-owned oil and gas companies and integrated service providers. For the fiscal year 2005, ExxonMobil and its ventures was the largest customer with approximately 14 percent of total revenues and ChevronTexaco and a consortium in which Chevron is a partner, Tengizchevroil (“TCO”) 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 in the notes to the consolidated financial statements.

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 $251.2 million at December 31, 2005. The Company’s $150.0 million principal amount of Senior Floating Rate Notes due 2010 estimated fair value was $154.3 million and $155.4 million on December 31, 2005 and December 31, 2004, respectively. The estimated fair value of the Company’s $175.0 million principal amount of 9.625% Senior Notes due 2013, based on quoted market prices was $196.4 million at December 31, 2004.

The fair values of the Company’s cash equivalents, auction rate securities held as investments, trade receivables, and trade payables approximated their carrying values due to the short-term nature of these instruments.

Stock-Based Compensation — The Company has elected the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and thus follows the provisions of Accounting Principles Board (“APB”) No. 25 “Accounting for Stock Issued to Employees” and related interpretations in accounting for its employee stock options. Accordingly, no compensation cost has been recognized for the Company’s stock option plans when the option price is equal to or greater than the fair market value of a share of the Company’s common stock on the date of grant. Pro forma net income (loss) and earnings (loss) per share are reflected in the following tables as if compensation cost had been determined based on the fair value of the options at their applicable grant

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

date, according to the provisions of SFAS No. 123. See Note 16 in the notes to the consolidated financial statements for the Company’s plan to adopt SFAS No. 123R.


	Year Ended December 31,
	2005			2004			2003
	(Dollars in Thousands)

Net income (loss) as reported	$	98,883		$	(47,083	)	$	(109,699	)
Stock-based compensation expense, net of tax, included in net income (loss) as reported		1,704			1,097			146
Stock-based compensation expense, net of tax, determined under fair value method		(1,855	)		(1,738	)		(1,423	)

Net income (loss) pro forma	$	98,732		$	(47,724	)	$	(110,976	)

Basic earnings (loss) per share:
Net income (loss) as reported	$	1.03		$	(0.50	)	$	(1.17	)
Net income (loss) pro forma	$	1.03		$	(0.51	)	$	(1.19	)
Diluted earnings (loss) per share:
Net income (loss) as reported	$	1.02		$	(0.50	)	$	(1.17	)
Net income (loss) pro forma	$	1.02		$	(0.51	)	$	(1.19	)

The fair value of each option grant is estimated using the Black-Scholes option pricing model with the following assumptions:


	2005	2004	2003

Expected price volatility	51.1%	60.0%	54.5%
Risk-free interest rate range	3.38%	1.95%-3.89%	2.78%-2.96%
Expected life of stock options	3-7 years	3-7 years	5-7 years

Options granted in 2005, 2004 and 2003 under the 1997 Stock Plan had an estimated fair value of $50 thousand, $0.4 million and $0.2 million, respectively.

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.

Reclassification — Certain reclassifications have been made to prior year balances to conform to the current year presentation.

Note 2 — Disposition of Assets

Discontinued Operations — Pursuant to a board approved plan to sell the Company’s Latin America assets and U.S. Gulf of Mexico offshore assets in 2003, the Company’s 2003 Form 10-K included these assets and related spare parts and inventories as discontinued operations. As a result of an impairment assessment in 2003, the Company recorded an impairment charge of $53.8 million related to the U.S. Gulf of Mexico offshore assets to reflect them at the estimated fair value. One of the rigs and related spare parts sold in 2003 for $1.8 million.

In September 2003, jackup rig 14 malfunctioned and became partially submerged. The Company received a total loss settlement of $27.0 million from its insurance underwriters. The cost incurred to tow the rig to the port and pay for the damage assessment approximated $4.0 million resulting in net insurance proceeds of approximately $23.0 million. The net book value of jackup rig 14 was $17.7 million at March 31, 2004. In compliance with GAAP, the Company was required to recognize the gain from the insurance proceeds in excess of the net book value of the asset. When considered separately from the other U.S. Gulf of Mexico offshore disposal group, this resulted in a gain of approximately $5.3 million from the damage to the rig. After considering the impact of the gain, the

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 — Disposition of Assets (continued)

Company determined that the overall valuation of the U.S. Gulf of Mexico offshore group was unchanged from that determined on June 30, 2003. As a result, the Company recognized an additional impairment of $5.3 million which, along with the gain, was reported in discontinued operations during the first quarter of 2004.

In early 2004, the board of directors concurred with the Company’s plan to actively pursue drilling contracts for certain of the Latin America land rigs in Mexico and in early May 2004, a subsidiary of the Company was awarded two contracts in Mexico utilizing seven Latin America land rigs. Based on this change in plan, the seven land rigs moved to Mexico were reclassified from discontinued operations to continuing operations effective May 2004. The remaining Latin America rigs were reclassified into continuing operations, as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires such if the assets do not sell or elicit a firm commitment for sale within one year they should be reclassified to continuing operations. Assets returned to continuing operations must be recorded at the lower of net book value less depreciation that would have been recorded if the assets had remained in continuing operations, or fair value. As a result, the Company recognized a $5.1 million impairment in 2004.

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. The Company received net proceeds of $39.3 million for the five jackup and four platform rigs. No gain or loss was recorded on the sale. Jackup rig 25 was sold on January 3, 2005. The Company received proceeds of $21.5 million and recognized an additional impairment on the disposition of $4.1 million in December 2004. 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.

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


	Year Ended December 31,
	2005			2004			2003
	(Dollars in Thousands)

U.S. jackup and platform drilling revenues	$	193		$	34,350		$	47,239

U.S. jackup and platform drilling gross margin	$	100		$	7,720		$	6,320
Depreciation and amortization		—			—			(9,817	)
Loss on disposition of assets, net of gains and impairments		(29	)		(4,238	)		(53,768	)

Income (loss) from discontinued operations	$	71		$	3,482		$	(57,265	)

Disposition of Assets — 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 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.

In August 2004, the Company sold the buildings and substantially all of its land in New Iberia, Louisiana relating to its drilling operations. The net sales price of approximately $6.4 million did not require any addition to the impairment of $3.4 million recorded in December 2003. Under the terms of the sale, the Company leased back certain portions of the land and office building under a two-year operating lease agreement.

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. Accordingly, the Company wrote off the net book value of the rig and recorded insurance proceeds of $13.8 million. Insurance proceeds received in excess of the net book value of assets destroyed resulted in a gain of $10.5 million, which $8.2 million was recognized in the second quarter of 2005 and $2.3 million recognized in the fourth quarter of 2005. 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)

Barge rig 74 was evacuated in March 2003 due to community unrest and sustained substantial damage. In December 2004, the Company received $18.5 million in insurance proceeds, reduced goodwill related to the rig by $6.8 million and recognized a gain of $0.9 million on the involuntary conversion of the rig.

Provision for Reduction in Carrying Value of an Asset — 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, chairman of the board and director of the Company, in anticipation of a settlement of its obligation under this arrangement. See Note 13 in the notes to the consolidated financial statements. In addition, barge rig 57 was damaged in July 2005 in a towing incident resulting in a $2.6 million impairment. On November 8, 2005, a well control incident on rig 247 occurred while operating under contract in Turkmenistan. Rig equipment is currently being 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. The Company does not expect any loss related to this incident as the rig is insured up to its replacement value subject to deductibles.

During 2004, the Company recognized a provision for reduction in carrying value of certain assets of $13.1 million comprised of:


	•	$3.2 million related to two U.S. Gulf of Mexico workover barges that were determined not to be marketable;

	•	$0.7 million to adjust two rigs in the Asia Pacific region to net realizable value;

	•	$2.4 million to adjust all assets in Bolivia to net realizable value in anticipation of their sale;

	•	$5.1 million reduction to adjust Latin America assets to fair value after reclassification of the assets from discontinued operations to continuing operations; and

	•	$1.7 million reserve against an asset comprised of insurance premiums paid on behalf of Robert L. Parker. See Note 13 in the notes to the consolidated financial statements.

During 2003, the Company recognized a provision for reduction in carrying value of certain assets of $6.0 million. Three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia, Louisiana were impaired by $2.6 million to estimated salvage value. In early 2004, the Company signed an agreement to sell the New Iberia, Louisiana land and buildings for a net sales price of $6.4 million. The sale was consummated in August 2004. This resulted in an impairment of $3.4 million at December 31, 2003, as the net book value of the property exceeded the net sales price.

Assets Held for Sale — The assets held for sale of $23.7 million at December 31, 2004 were mainly comprised of the estimated fair value of $0.7 million related to the Bolivia assets, jackup rig 25 at $21.5 million, the Company’s former headquarters in Tulsa, valued at $0.8 million and certain other equipment at $0.7 million. The sale of these assets was completed in 2005.

Note 3 — Goodwill

The Company’s goodwill balance at December 31, 2003 by reporting unit was: U.S. drilling barge rigs $56.8 million; international drilling Nigeria barge rigs $21.5 million and rental tools $36.1 million. In 2004, goodwill for the international drilling Nigeria barge rigs reporting unit was reduced $6.8 million for the asset disposal of barge rig 74. As of December 31, 2004, the goodwill balance by reporting unit was: U.S. drilling barge rigs $56.8 million; international drilling Nigeria barge rigs $14.7 million and rental tools $36.1 million. In 2005, barge rig 72 was moved to the U.S. Gulf of Mexico market and the related $7.4 million in goodwill was also moved. As of December 31, 2005, the goodwill balance by reporting unit was: U.S. drilling barge rigs $64.2 million; international drilling Nigeria barge rigs $7.3 million and rental tools $36.1 million.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 — Long-Term Debt


	December 31,
	2005		2004
	(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 (interest rate of 9.16% at December 31, 2005 and 7.15% at December 31, 2004)	$	150,000	$	150,000
Senior Notes payable in October 2013 with interest at 9.625% payable semi-annually in April and October net of unamortized premium of $5,015 at December 31, 2005 and $0 at December 31, 2004 (effective interest rate of 9.20% at December 31, 2005 and 2004)		230,015		175,000
Senior Notes payable in November 2009 with interest at 10.125% payable semi-annually in May and November, net of unamortized premium of $431 at December 31, 2004 (effective interest rate of 10.03% at December 31, 2004)		—		156,039
Capital lease		—		24

Total debt		380,015		481,063
Less current portion		—		24

Total long-term debt	$	380,015	$	481,039

The aggregate maturities of long-term debt for the five years ending December 31, 2010 are as follows: $0 for 2006-2009, $150.0 million for 2010 and $225.0 million thereafter.

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 percent. 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 the same date that the Company issued the additional $50.0 million of 9.625% Senior Notes (April 21, 2005), it issued a redemption notice for $65.0 million of its 10.125% Senior Notes at the redemption price of 105.0625 percent. The redemption date was May 21, 2005. An expense of $3.3 million was recognized as loss on extinguishment of debt.

On June 16, 2005, the Company issued a redemption notice to retire $30.0 million of its 10.125% Senior Notes at the redemption price of 105.0625 percent. The redemption date was July 16, 2005. 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 percent. The redemption was funded with cash on hand. An expense of $1.6 million was recognized as loss on extinguishment of debt.

Activity in 2004 — On July 30, 2004, the Company drew down the remaining $50.0 million on the delay draw term loan portion of the credit agreement dated October 10, 2003. These funds, along with existing cash, were used to retire the existing $64.4 million of 5.5% Convertible Subordinated Notes on August 2, 2004. On the same day, proceeds from the sale of five jackup rigs and four platform rigs were used to pay down $25.0 million of the delay draw term loan. On August 5, 2004, an additional $5.0 million was paid on the delay draw term loan with proceeds from the sale of the Company’s New Iberia facilities, leaving an outstanding balance of $70.0 million on the delay draw term loan.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 — Long-Term Debt (continued)

In September 2004, the Company refinanced a portion of its existing debt by issuing $150.0 million of Senior Floating Rate Notes due 2010. Proceeds were used to pay off the $70.0 million outstanding balance of the delay draw term loan and to retire $80.0 million of the 10.125% Senior Notes due 2009 that had been tendered pursuant to a tender offer dated August 6, 2004. Cash costs associated with the transaction totaled $9.7 million and were paid from existing cash. Cash costs included an early tender premium of 2.00 percent and a tender offer consideration of 104.54 percent on the $80.0 million tendered 10.125% Senior Notes, as well as underwriting, legal and other fees associated with the issuance of the $150.0 million Senior Floating Rate Notes. An expense of $8.2 million in debt extinguishment cost was recognized as a result of the refinancing.

In December 2004, the Company replaced its existing $50.0 million credit facility with a new $40.0 million credit facility that expires in December 2007. The new revolving credit facility is secured by rental tools equipment, accounts receivable and substantially all of the stock of the subsidiaries, and contains customary affirmative and negative covenants.

Activity in 2003 — In October 2003, the Company refinanced $325.0 million of its existing debt. The total refinancing package was comprised of $175.0 million of 9.625% Senior Notes due 2013 and a new $150.0 million senior credit agreement. The senior credit agreement consisted of a four-year $100.0 million delayed draw term loan facility and a three-year $50.0 million revolving credit facility. The proceeds of the 9.625% Senior Notes, plus an initial draw of $50.0 million under the term loan facility, were used to retire $184.3 million of the 9.75% Senior Notes due 2006 that had been tendered pursuant to a tender offer dated September 24, 2003. The balance was used to redeem the remaining 9.75% Senior Notes on November 15, 2003 at a call premium of 1.625 percent. As a result of the debt, the Company recorded $8.7 million of debt issuance cost which is being amortized over the term of the related debt. A charge of $5.3 million for loss on extinguishment of debt was incurred by the Company as a result of the debt refinancing.

Convertible Subordinated Notes — In July 1997, the Company issued $175.0 million of Convertible Subordinated Notes due 2004. The notes bore interest at 5.5% payable semi-annually in February and August. The notes were convertible at the option of the holder into shares of common stock of Parker Drilling at $15.39 per share at any time prior to maturity. The amount of outstanding notes at December 31, 2003 was $105.2 million. The Company repurchased $9.5 million of the outstanding notes in January 2004, $5.3 million in April 2004 and $25.0 million in May 2004 before paying off the remaining $64.4 million in August 2004. Debt extinguishment costs of $0.4 million was recognized as a result of the debt repayments.

For each of the Company’s Senior Note offerings, exchange offers 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.

Boeing Capital Note — On October 7, 1999, a wholly-owned subsidiary of the Company entered into a loan agreement with Boeing Capital Corporation for the refinancing of a portion of the capital cost of barge rig 75. The loan principal of approximately $24.8 million plus interest was being repaid in 60 monthly payments of approximately $0.5 million. The amount of principal outstanding at the end of 2003 was $5.1 million. The Company paid the remaining portion of the note in February 2004 at a 5.0 percent premium and recognized $0.2 million in debt extinguishment costs.

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 and Senior Floating Rate Notes (“the Notes”)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 5 — Guarantor/Non-Guarantor Consolidating Condensed Financial Statements (continued)

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.

AralParker (a Kazakhstan closed joint stock company, owned 50 percent by Parker Drilling (Kazakstan), Ltd. and 50 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 Inc.) and Universal Rig Leasing B.V. 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, 2005 and December 31, 2004 and for the years ended December 31, 2005, 2004 and 2003. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting. In addition, the consolidating condensed statement of cash flows includes a change to the 2004 presentation between the parent and guarantor columns from that which was previously reported to correct a mechanical error between these two columns. Cash flows from operating activities of the parent for the year ended December 31, 2004 have been increased by $58,274 and cash flows from operating activities of the guarantor have been reduced by the same amount. Also, cash flows from financing activities of the parent for the year ended December 31, 2004 have been reduced by $58,274 and cash flows from financing activities of the guarantor have been increased by the same amount.

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 STATEMENT OF OPERATIONS
(Dollars in Thousands)


	Year Ended December 31, 2004
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Drilling and rental revenues	$	—		$	280,120		$	104,695		$	(8,290	)	$	376,525
Drilling and rental operating expenses		2			160,583			98,319			(8,290	)		250,614
Depreciation and amortization		—			64,253			4,988			—			69,241

Drilling and rental operating income (loss)		(2	)		55,284			1,388			—			56,670

General and administrative expense (1)		53			(23,437	)		(29	)		—			(23,413	)
Provision for reduction in carrying value of certain assets		(1,782	)		(7,847	)		(3,491	)		—			(13,120	)
Gain on disposition of assets, net		—			50,529			10,121			(56,920	)		3,730

Total operating income (loss)		(1,731	)		74,529			7,989			(56,920	)		23,867

Other income and (expense):
Interest expense		(54,689	)		(48,590	)		(3,748	)		56,659			(50,368	)
Changes in fair value of derivative positions		(794	)		—			—			—			(794	)
Interest income		48,323			6,705			2,447			(56,659	)		816
Loss on extinguishment of debt		(8,753	)		—			—			—			(8,753	)
Minority interest		—			—			(1,143	)		—			(1,143	)
Other		763			32			12			12			819
Equity in net losses of subsidiaries		(29,137	)		—			—			29,137			—

Total other income and (expense)		(44,287	)		(41,853	)		(2,432	)		29,149			(59,423	)

Income (loss) before income taxes		(46,018	)		32,676			5,557			(27,771	)		(35,556	)
Income tax expense		1,065			12,685			1,259			—			15,009

Income (loss) from continuing operations		(47,083	)		19,991			4,298			(27,771	)		(50,565	)
Discontinued operations		—			3,482			—			—			3,482

Net income (loss)	$	(47,083	)	$	23,473		$	4,298		$	(27,771	)	$	(47,083	)


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

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


	Year Ended December 31, 2003
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Drilling and rental revenues	$	61		$	283,118		$	53,056		$	2,418		$	338,653
Drilling and rental operating expenses		1			176,684			43,889			2,418			222,992
Depreciation and amortization		—			67,757			5,922			—			73,679

Drilling and rental operating income		60			38,677			3,245			—			41,982

Construction contract revenue		—			7,030			—			—			7,030
Construction contract expense		—			5,030			—			—			5,030

Net construction contract operating income		—			2,000			—			—			2,000

General and administrative expense (1)		(112	)		(19,144	)		—			—			(19,256	)
Provision for reduction in carrying value of certain assets		—			(6,028	)		—			—			(6,028	)
Gain on disposition of assets, net		196			15,037			(24	)		(10,980	)		4,229

Total operating income (loss)		144			30,542			3,221			(10,980	)		22,927

Other income and (expense):
Interest expense		(58,543	)		(51,438	)		(4,153	)		60,344			(53,790	)
Interest income		55,691			3,968			1,698			(60,344	)		1,013
Loss on extinguishment of debt		(5,274	)		—			—			—			(5,274	)
Minority interest		—			—			464			—			464
Other		(10,979	)		(773	)		(17	)		10,980			(789	)
Equity in net losses of subsidiaries		(89,105	)		—			—			89,105			—

Total other income and (expense)		(108,210	)		(48,243	)		(2,008	)		100,085			(58,376	)

Income (loss) before income taxes		(108,066	)		(17,701	)		1,213			89,105			(35,449	)
Income tax expense		1,633			15,352			—			—			16,985

Income (loss) from continuing operations		(109,699	)		(33,053	)		1,213			89,105			(52,434	)
Discontinued operations		—			(57,265	)		—			—			(57,265	)

Net income (loss)	$	(109,699	)	$	(90,318	)	$	1,213		$	89,105		$	(109,699	)


(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, 2005
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

ASSETS
Current assets:
Cash and cash equivalents	$	31,978		$	11,145		$	17,053		$	—		$	60,176
Marketable securities		16,000			2,000			—			—			18,000
Accounts and notes receivable, net		41,965			112,888			41,637			(91,809	)		104,681
Rig materials and supplies		—			10,830			7,349			—			18,179
Deferred costs		—			2,791			1,432			—			4,223
Other current assets		12,024			63,312			740			—			76,076

Total current assets		101,967			202,966			68,211			(91,809	)		281,335

Property, plant and equipment, net		134			389,674			37,674			(72,085	)		355,397
Goodwill		—			107,606			—			—			107,606
Investment in subsidiaries and intercompany advances		606,711			737,080			37,895			(1,381,686	)		—
Other noncurrent assets		46,080			10,997			244			(39	)		57,282

Total assets	$	754,892		$	1,448,323		$	144,024		$	(1,545,619	)	$	801,620


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	38,802		$	163,414		$	50,446		$	(111,685	)	$	140,977
Accrued income taxes		609			9,885			(716	)		—			9,778

Total current liabilities		39,411			173,299			49,730			(111,685	)		150,755

Long-term debt		380,015			—			—			—			380,015
Other long-term liabilities		1,054			8,242			1,725			—			11,021
Intercompany payables		74,583			567,434			17,195			(659,212	)		—
Stockholders’ equity:
Common stock		16,306			39,899			21,251			(61,150	)		16,306
Capital in excess of par value		456,135			977,559			33,950			(1,011,509	)		456,135
Unamortized restricted stock plan compensation		(4,212	)		—			—			—			(4,212	)
Retained earnings (accumulated deficit)		(208,400	)		(318,110	)		20,173			297,937			(208,400	)

Total stockholders’ equity		259,829			699,348			75,374			(774,722	)		259,829

Total liabilities and stockholders’ equity	$	754,892		$	1,448,323		$	144,024		$	(1,545,619	)	$	801,620

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


	December 31, 2004
	Parent			Guarantor			Non-Guarantor		Eliminations			Consolidated

ASSETS
Current assets:
Cash and cash equivalents	$	16,677		$	7,938		$	19,652	$	—		$	44,267
Accounts and notes receivable, net		176,548			101,445			38,213		(216,891	)		99,315
Rig materials and supplies		—			13,593			5,613		—			19,206
Deferred costs		—			5,266			8,280		—			13,546
Other current assets		3,894			4,885			950		89			9,818

Total current assets		197,119			133,127			72,708		(216,802	)		186,152

Property, plant and equipment, net		134			415,027			38,177		(70,514	)		382,824
Assets held for sale		—			22,952			713		—			23,665
Goodwill		—			107,606			—		—			107,606
Investment in subsidiaries and intercompany advances		489,143			771,475			35,422		(1,296,040	)		—
Other noncurrent assets		14,005			11,007			1,331		—			26,343

Total assets	$	700,401		$	1,461,194		$	148,351	$	(1,583,356	)	$	726,590


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	24		$	—		$	—	$	—		$	24
Accounts payable and accrued liabilities		34,772			215,852			42,156		(220,155	)		72,625
Accrued income taxes		1,677			12,726			301		—			14,704

Total current liabilities		36,473			228,578			42,457		(220,155	)		87,353

Long-term debt		481,039			—			—		—			481,039
Other long-term liabilities		(40,611	)		48,578			1,275		39			9,281
Intercompany payables		74,583			593,674			29,695		(697,952	)		—
Stockholders’ equity:
Common stock		15,833			39,899			21,251		(61,150	)		15,833
Capital in excess of par value		441,085			977,563			33,783		(1,011,346	)		441,085
Unamortized restricted stock plan compensation		(718	)		—			—		—			(718	)
Retained earnings (accumulated deficit)		(307,283	)		(427,098	)		19,890		407,208			(307,283	)

Total stockholders’ equity		148,917			590,364			74,924		(665,288	)		148,917

Total liabilities and stockholders’ equity	$	700,401		$	1,461,194		$	148,351	$	(1,583,356	)	$	726,590

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	)
Other		1,713			1,200			—			—			2,913
Equity in net earnings of subsidiaries		(109,271	)		—			—			109,271			—
Change in 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

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


	Year Ended December 31, 2004
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Cash flows from operating activities:
Net income (loss)	$	(47,083	)	$	23,473		$	4,298		$	(27,771	)	$	(47,083	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		—			64,253			4,988			—			69,241
Amortization of debt issuance and premium		1,924			—			—			—			1,924
Loss on extinguishment of debt		2,657			—			—			—			2,657
Gain on disposition of assets		—			(50,419	)		(10,121	)		56,920			(3,620	)
Gain on disposition of marketable securities		(762	)		—			—			—			(762	)
Provision for reduction in carrying value of certain assets		1,782			11,975			3,491			—			17,248
Other		1,122			4,994			16			—			6,132
Equity in net losses of subsidiaries		29,137			—			—			(29,137	)		—
Change in assets and liabilities		(24,871	)		(7,941	)		15,889			(12	)		(16,935	)

Net cash provided by (used in) operating activities		(36,094	)		46,335			18,561			—			28,802

Cash flows from investing activities:
Capital expenditures		(1	)		(45,319	)		(1,998	)		—			(47,318	)
Proceeds from the sale of assets		—			50,324			729			—			51,053
Proceeds from insurance claims		—			41,566			—			—			41,566
Proceeds from sale of marketable securities		1,377			—			—			—			1,377

Net cash provided by (used in) investing activities		1,376			46,571			(1,269	)		—			46,678

Cash flows from financing activities:
Proceeds from issuance of debt		200,000			—			—			—			200,000
Principal payments under debt obligations		(290,206	)		—			—			—			(290,206	)
Payment of debt issuance costs		(10,243	)		—			—			—			(10,243	)
Proceeds from stock options exercised		1,471			—			—			—			1,471
Intercompany advances, net		97,318			(88,578	)		(8,740	)		—			—

Net cash provided by (used in) financing activities		(1,660	)		(88,578	)		(8,740	)		—			(98,978	)

Net increase (decrease) in cash and cash equivalents		(36,378	)		4,328			8,552			—			(23,498	)
Cash and cash equivalents at beginning of year		53,055			3,610			11,100			—			67,765

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

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


	Year Ended December 31, 2003
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated

Cash flows from operating activities:
Net income (loss)	$	(109,699	)	$	(90,318	)	$	1,213		$	89,105		$	(109,699	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			77,574			5,922			—			83,496
Amortization of debt issuance and premium		1,837			—			—			—			1,837
Loss on extinguishment of debt		1,161			—			—			—			1,161
Gain on disposition of assets		(196	)		(15,037	)		24			10,980			(4,229	)
Provision for reduction in carrying value of certain assets		—			59,796			—			—			59,796
Other		(842	)		4,405			—			—			3,563
Equity in net losses of subsidiaries		89,105			—			—			(89,105	)		—
Change in assets and liabilities		(53,159	)		68,287			2,195			9,206			26,529

Net cash provided by (used in) operating activities		(71,793	)		104,707			9,354			20,186			62,454

Cash flows from investing activities:
Capital expenditures		—			(34,895	)		(67	)		—			(34,962	)
Proceeds from the sale of assets		142			6,165			30			—			6,337
Proceeds from insurance claims		—			6,000			—			—			6,000

Net cash provided by (used in) investing activities		142			(22,730	)		(37	)		—			(22,625	)

Cash flows from financing activities:
Proceeds from issuance of debt		225,000			—			—			—			225,000
Principal payments under debt obligations		(239,064	)		(1,244	)		—			—			(240,308	)
Payment of debt issuance costs		(8,738	)		—			—			—			(8,738	)
Intercompany advances, net		104,254			(79,145	)		(4,923	)		(20,186	)		—

Net cash provided by (used in) financing activities		81,452			(80,389	)		(4,923	)		(20,186	)		(24,046	)

Net increase in cash and cash equivalents		9,801			1,588			4,394			—			15,783
Cash and cash equivalents at beginning of year		43,254			6,218			2,510			—			51,982

Cash and cash equivalents at end of year	$	53,055		$	7,806		$	6,904		$	—		$	67,765

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, 2005 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, 2005 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.

These swap agreements do not meet the hedge criteria in SFAS No. 133 and are, therefore, not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized currently in “Change in fair value of derivative positions” on the consolidated statement of operations. As of December 31, 2005, the Company had the following derivative instruments outstanding related to its interest rate swaps:


				Notional			Fixed			Fair
Effective Date		Termination Date		Amount		Floating Rate	Rate			Value
(Dollars in Thousands)

	September 1, 2005		September 2, 2008	$	50,000	Three-month LIBOR plus 475 basis points		8.83	%	$	553
	September 1, 2005		September 4, 2007	$	50,000	Three-month LIBOR plus 475 basis points		8.48	%		728

										$	1,281

Note 7 — Income Taxes

Income (loss) before income taxes and discontinued operations is summarized below:


	Year Ended December 31,
	2005		2004			2003
	(Dollars in Thousands)

United States	$	23,021	$	(14,847	)	$	(33,707	)
Foreign		47,207		(20,709	)		(1,742	)

	$	70,228	$	(35,556	)	$	(35,449	)

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,
	2005			2004		2003
	(Dollars in Thousands)

Current:
United States:
Federal	$	1,837		$	124	$	—
State		18			—		—
Foreign		14,473			14,885		16,985
Deferred:
United States:
Federal		(46,537	)		—		—
State		—			—		—
Foreign		1,625			—		—

	$	(28,584	)	$	15,009	$	16,985

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,
	2005						2004						2003
				% of						% of						% of
				Pre-Tax						Pre-Tax						Pre-Tax
	Amount			Income			Amount			Income			Amount			Income
	(Dollars in Thousands)

Computed expected tax expense	$	24,580			35	%	$	(12,445	)		(35	)%	$	(12,407	)		(35	)%
Foreign taxes, net of federal benefit		7,496			11	%		12,672			36	%		11,040			31	%
Change in valuation allowance		(71,497	)		(102	)%		12,231			34	%		11,858			33	%
Foreign corporation income		9,055			13	%		1,116			3	%		1,151			4	%
Permanent differences		1,740			2	%		1,311			4	%		4,701			13	%
Other		42			—			124			—			642			2	%

Actual tax expense	$	(28,584	)		(41	)%	$	15,009			42	%	$	16,985			48	%

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, 2005 and 2004 are shown below:


	December 31,
	2005			2004
	(Dollars in Thousands)

Deferred tax assets:
Current deferred tax assets:
Reserves established against realization of certain assets	$	5,951		$	8,112
Accruals not currently deductible for tax purposes		6,067			5,510

Gross current deferred tax assets		12,018			13,622
Current deferred tax valuation allowance		—			(9,728	)

Net current deferred tax assets		12,018			3,894

Long-term deferred tax assets:
Net operating loss carryforwards		34,783			64,275
Alternative minimum tax carryforwards		2,363			526
Property, plant and equipment		10,199			—
Other long-term liabilities		2,149			—
Deferred stock compensation		741			—

Gross long-term deferred tax assets		50,235			64,801
Long-term deferred tax valuation allowance		—			(46,275	)

Net long-term deferred tax assets		50,235			18,526

Net deferred tax assets		62,253			22,420

Deferred tax liabilities:
Long-term deferred tax liabilities:
Property, plant and equipment		—			(10,043	)
Goodwill		(12,234	)		(9,907	)
Other		(3,552	)		(2,470	)

Net long-term deferred tax liabilities		(15,786	)		(22,420	)

Net deferred tax asset	$	46,467		$	—

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.

The 2005 results reflect the reversal of the valuation allowance related to NOL carryforwards and other deferred tax assets in the U.S. The valuation allowance was originally recorded in accordance with GAAP as an offset to the Company’s deferred tax assets, which consisted primarily of NOL carryforwards. 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 NOL carryforwards and deferred tax assets in future periods. Having returned to profitability in 2005, the

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 — Income Taxes (continued)

Company now expects that earnings performance should allow the Company to benefit from the NOL carryforwards, the valuation allowance is no longer required. In 2006 the Company will begin to report deferred income tax expense. In 2004, the total change in valuation allowance of $37.1 million consisted of a $12.2 million current increase in the valuation allowance. The remainder was due mainly to a change in the deferred tax liabilities resulting from asset sales planned in 2003 which were not realized. During 2005 and prior to the reversal of the valuation allowance as discussed below, 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.

The $29.5 million decrease in the NOL carryforward component of deferred tax assets in 2005 is primarily due to projected utilization of NOL carryforwards in the Company’s 2005 federal income tax return to be filed in 2006. The $56.0 million decrease in the valuation allowance component in 2005 is primarily due to expected utilization of the Company’s remaining NOL in 2006 and beyond. At December 31, 2005, the Company had $99.5 million of gross NOL carryforwards. For tax purposes, the NOL carryforwards expire over a 20-year period ending December 31 as follows: 2018 — $19.6 million; 2019 — $7.6 million; thereafter — $72.3 million.

The Company has provided U.S. deferred taxes and withholding taxes on the unremitted earnings of our U.S. and foreign subsidiaries as the earnings are not currently considered to be permanently reinvested. As of December 31, 2005, the amounts accrued for tax contingencies totaled $22.9 million, with $6.6 million classified as long-term and included in “Other long-term liabilities.”

Note 8 — Common Stock and Stockholders’ Equity

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.

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.

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.

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Common Stock and Stockholders’ Equity (continued)

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.

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.

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


	1991 Stock
	Grant Plan
	Restricted
	Shares

Outstanding at December 31, 2004		—
Granted		100,000
Exercised		—
Cancelled		—

Outstanding at December 31, 2005		100,000

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Common Stock and Stockholders’ Equity (continued)


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

Outstanding at December 31, 2002		200,000		$	8.431
Granted		—			—
Exercised		—			—
Cancelled		—			—

Outstanding at December 31, 2003		200,000			8.431
Granted		—			—
Exercised		—			—
Cancelled		—			—

Outstanding at December 31, 2004		200,000			8.431
Granted		—			—
Exercised		(21,000	)		5.313
Cancelled		(55,000	)		8.031

Outstanding at December 31, 2005		124,000		$	9.137


	1994 Executive Stock Option Plan
	Incentive Options					Non-Qualified Options
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Outstanding at December 31, 2002		605,564		$	7.303		1,566,936		$	7.585
Granted		—			—		—			—
Exercised		—			—		—			—
Cancelled		(27,000	)		7.741		—			—

Outstanding at December 31, 2003		578,564			7.286		1,566,936			7.585
Granted		—			—		—			—
Exercised		—			—		(55,500	)		2.250
Cancelled		(195,268	)		6.687		(346,732	)		7.811

Outstanding at December 31, 2004		383,296			7.587		1,164,704			7.767
Granted		—			—		—			—
Exercised		(61,267	)		8.875		(26,199	)		8.875
Cancelled		(180,490	)		6.139		(347,510	)		5.160

Outstanding at December 31, 2005		141,539		$	8.875		790,995		$	8.875

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Common Stock and Stockholders’ Equity (continued)


	1997 Stock Plan
	Incentive Options					Non-Qualified Options
				Weighted					Weighted
				Average					Average
				Exercise					Exercise		Restricted
	Shares			Price		Shares			Price		Shares
Outstanding at December 31, 2002		2,489,760		$	8.422		4,747,550		$	4.924		30,000
Granted		62,402			8.322		262,598			3.736		755,000
Exercised		—			—		—			—		(6,000	)
Cancelled		(50,513	)		10.314		(52,488	)		4.020		—

Outstanding at December 31, 2003		2,501,649			8.382		4,957,660			4.887		779,000
Granted		—			—		200,000			4.020		—
Exercised		(94,764	)		3.196		(398,956	)		2.641		(383,500	)
Cancelled		(571,946	)		9.907		(586,989	)		7.071		(37,500	)

Outstanding at December 31, 2004		1,834,939			8.174		4,171,715			4.752		358,000
Granted		—			—		25,000			3.850		—
Exercised		(339,689	)		3.942		(1,161,649	)		3.838		(358,000	)
Cancelled		(289,882	)		9.915		(403,618	)		5.394		—

Outstanding at December 31, 2005		1,205,368		$	8.947		2,631,448		$	5.049		—


	2005 Long-Term Incentive Plan
	Non-Qualified Options
			Weighted
			Average
			Exercise		Restricted
	Shares		Price		Shares

Outstanding at December 31, 2004		—	$	—		—
Granted		100,000		8.875		1,027,500
Exercised		—		—		—
Cancelled		—		—		(22,500	)

Outstanding at December 31, 2005		100,000	$	8.875		1,005,000

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Common Stock and Stockholders’ Equity (continued)

The following tables summarize the information regarding stock options outstanding and exercisable as of December 31, 2005:


				Outstanding Options
				Weighted
				Average		Weighted
				Remaining		Average
		Number of		Contractual		Exercise
Plan	Exercise Prices	Shares		Life		Price

1994 Non-Employee Director Incentive Plan
Non-qualified	$3.281		4,000		3.0 years	$	3.281
Non-qualified	$8.875 – $12.094		120,000		1.0 years	$	9.332
1994 Executive Stock Option Plan
Incentive option	$8.875		141,539		1.1 years	$	8.875
Non-qualified	$8.875		790,995		1.2 years	$	8.875
1997 Stock Plan
Incentive option	$3.188 – $5.938		307,652		0.5 years	$	3.634
Incentive option	$8.875 – $12.188		897,716		1.5 years	$	10.768
Non-qualified	$1.960 – $6.070		1,925,698		2.7 years	$	3.643
Non-qualified	$8.875 – $10.813		705,750		1.2 years	$	8.885
2005 Long-Term Incentive Plan
Non-qualified	$8.875		100,000		1.4 years	$	8.875


		Exercisable Options
				Weighted
				Average
		Number of		Exercise
Plan	Exercise Prices	Shares		Price

1994 Non-Employee Director Incentive Plan
Non-qualified	$3.281		4,000	$	3.281
Non-qualified	$8.875 – $12.094		120,000	$	9.332
1994 Executive Stock Option Plan
Incentive option	$8.875		141,539	$	8.875
Non-qualified	$8.875		790,995	$	8.875
1997 Stock Plan
Incentive option	$3.188 – $5.938		307,652	$	3.634
Incentive option	$8.875 – $12.188		897,716	$	10.768
Non-qualified	$1.960 – $6.070		1,839,281	$	3.645
Non-qualified	$8.875 – $10.813		705,750	$	8.885
2005 Long-Term Incentive Plan
Non-qualified	$8.875		100,000	$	8.875

The Company had 760,699 and 660,389 shares held in Treasury stock at December 31, 2005 and 2004, respectively.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 8 — Common Stock and Stockholders’ Equity (continued)

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


	December 31,
	2005		2004
Stock plans		7,938,484		11,671,475
Stock bonus plan		307,187		512,198

Total shares reserved for issuance		8,245,671		12,183,673

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.

Common Stock Offering — Subsequent to December 31, 2005, the Company announced an offering of 8,900,000 shares of common stock on January 18, 2006, pursuant to a Free Writing Prospectus dated January 17, 2006 and a Prospectus Supplement dated January 18, 2006. On January 23, 2006, the Company realized $11.23 per share or a total of $99.9 million of net proceeds before expenses, but after underwriter discount, from the offering.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 9 — Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS)


	For the Year Ended December 31, 2005
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic EPS:
Income from continuing operations	$	98,812,000		95,818,893	$	1.03
Discontinued operations		71,000				0.00

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				0.00

Net income	$	98,883,000			$	1.02


	For the Year Ended December 31, 2004
	Income (Loss)			Shares		Per-Share
	(Numerator)			(Denominator)		Amount

Basic EPS:
Loss from continuing operations	$	(50,565,000	)		94,113,257	$	(0.54	)
Discontinued operations		3,482,000					0.04

Net loss	$	(47,083,000	)			$	(0.50	)

Effect of dilutive securities:
Stock options and restricted stock					—		—
Convertible debt					—		—
Diluted EPS:
Loss from continuing operations	$	(50,565,000	)		94,113,257	$	(0.54	)
Discontinued operations		3,482,000					0.04

Net loss	$	(47,083,000	)			$	(0.50	)


	For the Year Ended December 31, 2003
	Loss			Shares		Per-Share
	(Numerator)			(Denominator)		Amount

Basic EPS:
Loss from continuing operations	$	(52,434,000	)		93,420,713	$	(0.56	)
Discontinued operations		(57,265,000	)				(0.61	)

Net loss	$	(109,699,000	)			$	(1.17	)

Effect of dilutive securities:
Stock options and restricted stock					—		—
Convertible debt					—		—
Diluted EPS:
Loss from continuing operations	$	(52,434,000	)		93,420,713	$	(0.56	)
Discontinued operations		(57,265,000	)				(0.61	)

Net loss	$	(109,699,000	)			$	(1.17	)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 9 — Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS) (continued)

Options to purchase 2,796,000 shares of common stock with exercise prices ranging from $8.875 to $12.188 per share were outstanding during the year ended December 31, 2005, 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, 2004, options to purchase 7,754,654 shares of common stock at prices ranging from $1.960 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 due to the net loss incurred for 2004. For the fiscal year ended December 31, 2003, options to purchase 9,804,809 shares of common stock at prices ranging from $1.960 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 due to the net loss during 2003. At December 31, 2003, the Company had outstanding $105,169,000 of 5.5% Convertible Subordinated Notes which were convertible into 6,833,593 shares of common stock at $15.39 per share. The notes were outstanding since their issuance in July 1997 but were not included in the computation of diluted EPS because the assumed conversion of the notes would have had an anti-dilutive effect on EPS. All of the outstanding 5.5% Convertible Subordinated Notes were retired on August 2, 2004.

Note 10 — Employee Benefit Plans

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. The Company issued 205,011, 402,760, and 627,732 shares to the Plan in 2005, 2004 and 2003 respectively with the Company recognizing expense of $1.4 million, $1.4 million, and $1.7 million for each of the respective periods.

Parker Drilling Company Limited (“PDCL”), a wholly-owned subsidiary of the Company, had a deferred compensation plan (“Compensation Plan”) of certain designated non-resident alien employees of PDCL and its affiliates. The Compensation Plan was terminated in 2004. The Compensation Plan was valued at $1.8 million when terminated in 2004 and $1.7 million as of December 31, 2003, respectively. The Company recognized expense of $0.3 million and $0.2 million in each of the years ending December 31, 2004 and 2003. As of December 31, 2004 and 2005, the Company had no deferred compensation plan.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 — 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	2005			2004			2003
	(Dollars in Thousands)

Drilling and rental revenues:
U.S. drilling (1)	$	128,252		$	88,512		$	67,449
International drilling (1)		308,572			220,846			216,567
Rental tools (1)		94,838			67,167			54,637

Total drilling and rental revenues		531,662			376,525			338,653

Drilling and rental operating income (loss): (2)
U.S. drilling		41,739			15,938			(186	)
International drilling		40,281			15,858			24,557
Rental tools		40,239			24,874			17,611

Total drilling and rental operating income		122,259			56,670			41,982
Net construction contract operating income		—			—			2,000
General and administrative expense		(27,830	)		(23,413	)		(19,256	)
Provision for reduction in carrying value of certain assets		(4,884	)		(13,120	)		(6,028	)
Gain on disposition of assets, net		25,578			3,730			4,229

Total operating income		115,123			23,867			22,927
Interest expense		(42,113	)		(50,368	)		(53,790	)
Changes in fair value of derivative positions		2,076			(794	)		—
Loss on extinguishment of debt		(8,241	)		(8,753	)		(5,274	)
Minority interest		1,905			(1,143	)		464
Other		1,478			1,635			224

Income (loss) from continuing operations before income taxes	$	70,228		$	(35,556	)	$	(35,449	)

Identifiable assets: (3)
U.S. drilling	$	120,647		$	133,855		$	227,479
International drilling		378,427			371,059			413,338
Rental tools		98,531			82,569			77,940

Total identifiable assets		597,605			587,483			718,757
Corporate assets		204,015			139,107			128,875

Total assets	$	801,620		$	726,590		$	847,632


(1)		In 2005, ExxonMobil (inclusive of its ventures) and ChevronTexaco (inclusive of TCO, a consortium in which ChevronTexaco is a partner) accounted for approximately 14 percent and 11 percent of the Company’s total revenues, respectively. ExxonMobil (inclusive of its ventures) 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. ChevronTexaco (inclusive of TCO, a consortium in which ChevronTexaco is a partner) 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. In 2004, TCO accounted for approximately 13 percent of total revenues, all relating to the international drilling segment. In 2003, Royal Dutch Shell, TCO and ChevronTexaco accounted for approximately 15 percent, 14 percent and 11 percent of the Company’s total revenues, respectively. Royal Dutch Shell and TCO amounts all related to the Company’s international drilling segment. ChevronTexaco accounted for approximately $24.4 million of the Company’s U.S. drilling segment revenues, $10.3 million of the Company’s international drilling segment revenues and $7.1 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.

(3)		Includes assets related to discontinued operations.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 — Business Segments (continued)


	Year Ended December 31,
Operations by Geographic Area	2005			2004			2003
	(Dollars in Thousands)

Drilling and rental revenues:
United States	$	218,056		$	154,995		$	122,086
Latin America		67,954			39,614			24,869
Asia Pacific		58,623			42,468			28,492
Africa and Middle East		33,377			31,352			56,601
CIS		153,652			108,096			106,605

Total drilling and rental revenues		531,662			376,525			338,653

Drilling and rental operating income (loss): (1)
United States		77,560			40,130			17,425
Latin America		4,018			(1,215	)		(1,345	)
Asia Pacific		14,353			9,379			3,309
Africa and Middle East		(834	)		(8,181	)		3,316
CIS		27,162			16,557			19,277

Total drilling and rental operating income		122,259			56,670			41,982

Net construction contract operating income (United States)		—			—			2,000
General and administrative expense		(27,830	)		(23,413	)		(19,256	)
Provision for reduction in carrying value of certain assets		(4,884	)		(13,120	)		(6,028	)
Gain on disposition of assets, net		25,578			3,730			4,229

Total operating income		115,123			23,867			22,927
Interest expense		(42,113	)		(50,368	)		(53,790	)
Changes in fair value of derivative positions		2,076			(794	)		—
Loss on extinguishment of debt		(8,241	)		(8,753	)		(5,274	)
Minority interest		1,905			(1,143	)		464
Other		1,478			1,635			224

Income (loss) from continuing operations before income taxes	$	70,228		$	(35,556	)	$	(35,449	)

Long-lived assets: (2)
United States	$	257,302		$	262,416		$	354,320
Latin America		36,853			55,425			52,320
Asia Pacific		18,732			20,785			25,027
Africa and Middle East		51,615			65,974			85,661
CIS		98,501			109,495			124,224

Total long-lived assets	$	463,003		$	514,095		$	641,552


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

(2)		Includes assets related to discontinued operations and is comprised of property, plant and equipment, net and goodwill.

Note 12 — Commitments and Contingencies

At December 31, 2005, the Company had a $40.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2005, $10.3 million of availability has been

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

reserved to support letters of credit that have been issued. At December 31, 2005, no amounts had been drawn under the revolving credit facility.

The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend through 2012 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses. Future minimum lease payments at December 31, 2005, under operating leases with non-cancelable terms are as follows (dollars in thousands):


2006	$	5,166
2007		2,725
2008		2,330
2009		1,558
2010		520
Thereafter		951

Total	$	13,250

Total rent expense for all operating leases amounted to $10.2 million for 2005, $9.3 million for 2004, and $10.3 million for 2003.

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. There is no assurance that such coverage will adequately protect the Company against liability from all potential consequences.

As of December 31, 2005, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $9.4 million and the related insurance recoveries/receivables were $3.8 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, considers that any liability resulting from these matters would not materially affect the results of operations, the financial position or the net cash flows of the Company.

As previously reported, the Kazakhstan branch (“PKD Kazakhstan”) of Parker Drilling Company International Limited (“PDCIL”) prevailed on its Kazakhstan Supreme Court appeal arising out of an audit assessment in 2001 of approximately $29.0 million by the Ministry of State Revenues of Kazakhstan (“MSR”) based on payments PDCIL received from the operator to upgrade barge rig 257. Although the MSR did not appeal this Supreme Court ruling

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

within the time required for a supervisory appeal, in February 2005 the Ministry of Finance of Kazakhstan (“MinFin”) filed an application for re-hearing based on new evidence and the Supreme Court of Kazakhstan issued an order on April 12, 2005, declining the application for re-hearing.

On October 14, 2005, PKD Kazakhstan received an Act of Tax Audit from MinFin assessing PKD Kazakhstan, in the amount of $111.4 million. Approximately $56.4 million was assessed for import Value Added Tax, administrative fines and interest on equipment imported to perform drilling contracts, (the “VAT Assessment”). The VAT Assessment is based on an interpretation by MinFin that resolutions of the Government of the Republic of Kazakhstan and MinFin removing import Value Added Tax exemptions should be applied retroactively. PKD Kazakhstan is contesting this assessment. In addition, the client of PKD Kazakhstan has agreed to reimburse the VAT Assessment, when and if PKD Kazakhstan is required to pay. At December 31, 2005, the $56.4 million VAT Assessment is reflected in “Accrued liabilities” in the consolidated balance sheet with the corresponding $56.4 million reimbursement receivable from the customer reported in “Other current assets.” Approximately $55.0 million was assessed for corporate income tax, individual income tax and social tax, administrative fines and interest in connection with the reimbursements received from PKD Kazakhstan’s customer for the upgrade of barge rig 257 and other issues, (the “Income Tax Assessment”). The Income Tax Assessment is based on the same claim of MinFin on which PKD Kazakhstan has prevailed in the Supreme Court of Kazakhstan on two previous occasions. PKD Kazakhstan believes that this claim is barred by the statute of limitations and will ultimately be dismissed.

The Company continues to pursue its petition with the U.S. Treasury Department for Competent Authority review, which is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. The U.S. Treasury Department has granted the Company’s petition and has plans to re-initiate proceedings with MinFin.

In September 2005, a subsidiary of the Company was served with a lawsuit filed on behalf of numerous citizens of Bangladesh claiming $250 million in damages due to various types of property damage and personal injuries, arising as a result of two blowouts, only one of which involved the Company, that occurred in Bangladesh in January and July 2005. This case is in the very early stages of discovery and, accordingly, the ultimate outcome cannot presently be determined. In any event the Company believes that the outcome of this lawsuit will not materially impair the financial condition of the Company due to insurance coverage and contractual indemnities.

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 those 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. Because the progress of these cases has been delayed by procedural challenges raised by the defendants and by the impact of Hurricane Katrina on Mississippi, the Company has not yet had an opportunity to conduct sufficient discovery to determine the number of plaintiffs, if any, that were employed by the Company or otherwise have any connection with its drilling operations during the relevant period. In addition, on March 18, 2005, a case was filed by a single plaintiff in the Circuit Court of Madison County, Illinois against approximately 125 defendants, including Parker Drilling Company, alleging that the plaintiff suffers from asbestos-related diseases, including mesothelioma, as a result of exposure to asbestos and asbestos-containing products. On January 13, 2006, one of the Company’s subsidiaries was served with a petition filed in the District Court for the Parish of Jefferson in Louisiana against more than 200 defendants by 88 plaintiffs complaining of exposure to asbestos, chemicals, noise, and metals during their work as Jones Act seamen. There has not yet been an opportunity to conduct sufficient discovery to determine the number of plaintiffs, if any, that were employed by a subsidiary of the Company or otherwise have any connection with any of its subsidiary operations during the relevant period. The plaintiffs in these cases seek, among other things, awards of unspecified compensatory and punitive damages. The subsidiary intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of these lawsuits to have a material adverse effect

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits.

Note 13 — Related Party Transactions

On February 27, 1995, the Company entered into a Split Dollar Life Insurance Agreement with Robert L. Parker, chairman of the board and director of the Company, and the Robert L. Parker and Catherine M. Parker Family Trust under Indenture dated 23rd day of July 1993 (“Trust”) pursuant to which the Company agreed to provide life insurance protection for Mr. and Mrs. Robert L. Parker in the event of the death of Mr. and Mrs. Parker (the “Agreement”). The Agreement provided that the Trust would acquire and own a life insurance policy with face amount of $13.2 million and that the Company would pay the premiums subject to reimbursement by the Trust out of the proceeds of the policy, with interest to accrue on the premium payments made by the Company from and after January 1, 2000, at the one-year Treasury bill rate. The repayment of the premiums was secured by an Assignment of Life Insurance Policy as Collateral on the same date as the Agreement. On October 14, 1996, the Agreement was amended to provide that the interest accrual would be deferred until February 28, 2003, in consideration for the Company’s termination of a separate life insurance policy on the life of Robert L. Parker. On April 19, 2000, the Agreement was amended and restated to replace the previous policy with two policies, one for $8.0 million on the life of Robert L. Parker and one for $7.7 million on the lives of both Mr. and Mrs. Robert L. Parker. Mr. Robert L. Parker Jr., the Company’s president and chief executive officer and son of Robert L. Parker, will receive one third of the net proceeds of the policies.

As of December 31, 2005, the amount of premiums paid by the Company on the policies and to be reimbursed by the Trust to the Company was $4.7 million. Due to the adoption of the Sarbanes-Oxley Act of 2002 (“SOX”), additional loans to executive officers and directors may be prohibited, although continuance of loans in existence as of July 30, 2002, are allowed provided there is no material modification to such loans. Because the advancement of additional annual premiums by the Company may be considered a prohibited loan under the SOX, the Company elected to not advance the annual premiums that were due in December 2002, 2003, 2004 and 2005 pending further clarification from the SEC as to how the Company’s obligation to advance these premiums under the Agreement can be honored without violating the SOX. An analysis of the policies by a financial consultant indicated there is no reasonable certainty that the value of the policies will be adequate for the Company to recoup the full amount of premiums. Therefore, during 2005 and 2004, the Company reduced the value of its asset by $2.3 million and $1.7 million, respectively.

Robert L. Parker, through the Robert L. Parker, Sr. Family Limited Partnership (the “Limited Partnership”) owns a 2,987 acre ranch near Kerrville, Texas, the (“Cypress Springs Ranch”) and a 4,982 acre ranch in Mazie, Oklahoma (the “Mazie Ranch”). The Cypress Springs Ranch has lodging, conference facilities, sporting and other outdoor activities which the Company utilized in connection with marketing and other business purposes during 2005 and 2004. The Mazie Ranch has hunting, fishing and other outdoor facilities. Effective as of January 1, 2004, the Company and the Limited Partnership entered into a Lease Agreement pursuant to which the Company pays the Limited Partnership a monthly fee in exchange for unlimited access to the facilities of the Limited Partnership at the Cypress Springs Ranch and the Mazie Ranch. During 2005 and 2004, the Company paid the Limited Partnership a total of $0.4 million in lease fees per year. The Limited Partnership also entered into a Services Agreement with the Company effective January 1, 2004, pursuant to which the Company provides certain personnel to the Limited Partnership to maintain the Cypress Springs Ranch and the Mazie Ranch. During 2005 and 2004, the Limited Partnership paid the Company a total of $0.2 million for the provision of such personnel per year.

Robert L. Parker Jr. owns a 1,400 acre ranch near Kerrville, Texas (the “Camp Verde Ranch”). The Camp Verde Ranch has lodging as well as hunting, fishing and other outdoor facilities. Effective January 1, 2004, the Company entered into a Lease Agreement pursuant to which the Company pays Robert L. Parker Jr. a monthly fee in exchange for unlimited access to the Camp Verde Ranch facilities. During 2005 and 2004, the Company paid Robert L. Parker Jr. a total of $0.1 million in lease fees per year. Mr. Parker Jr. also entered into a Services Agreement with the Company effective as of January 1, 2004, pursuant to which the Company provides certain personnel to Mr. Parker Jr. to maintain the Camp Verde Ranch. During 2005 and 2004, Mr. Parker Jr. paid the Company a total of $58 thousand and $36 thousand for the provision of such personnel, respectively.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Related Party Transactions (continued)

During 2005, one of the Company’s directors held the position of executive vice president and chief financial officer of Apache Corporation (“Apache”). During 2005, subsidiaries of the Company recognized $6.7 million in gross revenues for performance of drilling services and provision of rental tools for a subsidiary of Apache.

Note 14 — Supplementary Information

At December 31, 2005, accrued liabilities included $6.5 million of accrued interest expense, $7.9 million of workers’ compensation and health plan liabilities, $25.6 million of accrued payroll and payroll taxes and $56.4 million for the VAT Assessment discussed in Note 12 in the notes to the consolidated financial statements. At December 31, 2004, accrued liabilities included $7.0 million of accrued interest expense, $5.7 million of workers’ compensation and health plan liabilities and $16.8 million of accrued payroll and payroll taxes. Other long-term obligations included $2.0 million and $2.3 million of workers’ compensation liabilities as of December 31, 2005 and 2004, respectively.

Note 15 — Selected Quarterly Financial Data


	Quarter
Year 2005	First		Second (2)			Third (2)			Fourth (2)		Total (2)
	(Dollars in Thousands Except Per Share Data)
	(Unaudited)

Revenues	$	120,243	$	133,954		$	127,905		$	149,560	$	531,662
Drilling and rental operating income	$	24,991	$	29,322		$	32,665		$	35,281	$	122,259
Total operating income	$	18,567	$	38,820		$	29,865		$	27,871	$	115,123
Income from continuing operations	$	3,838	$	20,194		$	18,073		$	56,707	$	98,812
Discontinued operations	$	91	$	(14	)	$	(6	)	$	—	$	71
Net income	$	3,929	$	20,180		$	18,067		$	56,707	$	98,883
Basic earnings per share: (1)
Income from continuing operations	$	0.04	$	0.21		$	0.19		$	0.59	$	1.03
Discontinued operations	$	—	$	—		$	—		$	—	$	—
Net income	$	0.04	$	0.21		$	0.19		$	0.59	$	1.03
Diluted earnings per share: (1)
Income from continuing operations	$	0.04	$	0.21		$	0.18		$	0.58	$	1.02
Discontinued operations	$	—	$	—		$	—		$	—	$	—
Net income	$	0.04	$	0.21		$	0.18		$	0.58	$	1.02


(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 $4.9 million provision for reduction in carrying value of certain assets in 2005; $2.3 million and $2.6 million in the third and fourth quarters, respectively. Also included is a gain on the disposition of assets for the seven land rigs in Latin America and rig 255 in Bangladesh of $15.0 million, $6.0 million and $3.3 million in the second, third and fourth quarters of 2005, respectively. Net income in the fourth quarter includes the reversal of a $71.5 million valuation allowance related to net operating loss carryforwards and other deferred assets. See Note 7 in the notes to the consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 15 — Selected Quarterly Financial Data (continued)


	Quarter
Year 2004	First			Second (2)			Third			Fourth (2)			Total (2)
	(Dollars in Thousands Except Per Share Data)
	(Unaudited)

Revenues	$	90,899		$	87,881		$	87,945		$	109,800		$	376,525
Drilling and rental operating income	$	15,455		$	13,616		$	6,358		$	21,241		$	56,670
Total operating income	$	10,136		$	412		$	1,767		$	11,552		$	23,867
Loss from continuing operations	$	(7,594	)	$	(16,022	)	$	(24,802	)	$	(2,147	)	$	(50,565	)
Discontinued operations	$	2,730		$	2,497		$	1,359		$	(3,104	)	$	3,482
Net loss	$	(4,864	)	$	(13,525	)	$	(23,443	)	$	(5,251	)	$	(47,083	)
Basic earnings (loss) per share: (1)
Loss from continuing operations	$	(0.08	)	$	(0.17	)	$	(0.26	)	$	(0.03	)	$	(0.54	)
Discontinued operations	$	0.03		$	0.03		$	0.01		$	(0.03	)	$	0.04
Net loss	$	(0.05	)	$	(0.14	)	$	(0.25	)	$	(0.06	)	$	(0.50	)
Diluted earnings (loss) per share: (1)
Loss from continuing operations	$	(0.08	)	$	(0.17	)	$	(0.26	)	$	(0.03	)	$	(0.54	)
Discontinued operations	$	0.03		$	0.03		$	0.01		$	(0.03	)	$	0.04
Net loss	$	(0.05	)	$	(0.14	)	$	(0.25	)	$	(0.06	)	$	(0.50	)


(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 loss includes a $13.1 million provision for reduction in carrying value of certain assets in 2004; $6.5 million and $6.6 million in the second and fourth quarters, respectively.

Note 16 — Recent Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN No. 47 requires companies to record a liability for those asset retirement obligations in which the timing and/or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS No. 143, “Accounting for Asset Retirement Obligations,” which the Company adopted on January 1, 2003. FIN No. 47, which was adopted October 1, 2005, requires the Company to accrue a liability when a range of scenarios indicates that the potential timing and/or settlement amounts of the conditional asset retirement obligations can be determined. This pronouncement did not have any impact on the consolidated financial statements.

In May 2005, FASB issued SFAS No. 154, “Accounting Changes and Error Corrections a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by this Statement. The Company will adopt this standard effective January 1, 2006 and it does not expect any impact on its consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the SEC approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123R are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this standard until the first quarter of 2006.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 16 — Recent Accounting Pronouncements (continued)

Its plans are to use the modified prospective application method as detailed in SFAS 123R. The Company expects the impact on its consolidated financial statements to be consistent with the impact disclosed in Note 1 of the notes to the consolidated financial statements. The Company’s future cash flows will not be impacted by the adoption of this standard. See “Stock-Based Compensation” within Note 1 of the notes to the consolidated financial statements for further information.

In October 2005, the FASB issued FASB Staff Position (“FSP”) FAS 123R-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123R.” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123R. The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements as long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with its adoption of SFAS 123R.

In November 2005, the FASB issued FSP SFAS No. 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” in response to issues financial statement preparers raised about the ability to calculate estimated tax benefit amounts that would have qualified if the entity had adopted SFAS No. 123 for recognition purposes in 1995 as opposed to opting for the disclosure of the pro forma effects. The position provides for a transition method that provides a proscribed computation for the estimated beginning balance of the related additional paid in capital pool and a simplified method to determine the subsequent impact on the pool relating to employee option awards that are fully vested and outstanding upon adoption of SFAS No. 123R. The Company is currently evaluating the impact of this position on its calculation upon adoption of SFAS No. 123R in 2006.


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

This item is not applicable to the Company in that disclosure is required under Regulation S-X by the SEC only if the Company had changed independent auditors and, if it had, only under certain circumstances.


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, 2005. 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 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 assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 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, 2005.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that is included herein.

PART III


ITEM 10.	*DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT*

Information with respect to directors can be found under the caption; “Item 1 — Election of Directors” and “Board of Directors” of the Company’s 2006 Proxy Statement for the Annual Meeting of Shareholders to be held on April 28, 2006. Such information is incorporated herein by reference.

Information with respect to executive officers is shown in Item 4A of this report on 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 2006 Proxy Statement and is incorporated herein by reference.

The information in the Company’s 2006 Proxy Statement set forth under the caption; “Section 16(a) Beneficial Reporting Compliance” is incorporated herein by reference.

The Company has adopted the Parker Drilling Code of Corporate Conduct (“CCC”) which includes a code of financial 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” and “Director Compensation” in the Company’s 2006 Proxy Statement is incorporated herein by reference. Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulations S-K, the information contained in the Company’s proxy statement under the sub-heading “Compensation Committee Report on Executive Compensation” and “Performance Graph” shall not be deemed to be filed as part of or incorporated by reference into this Form 10-K.


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 “Equity Ownership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in the Company’s 2006 Proxy Statement.


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 “Related Party Transactions” in the Company’s 2006 Proxy Statement for the Annual Meeting of Shareholders to be held April 28, 2006, to be filed with the SEC within 120 days of the end of the Company’s year ended December 31, 2005.


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 Accountant” in the Company’s 2006 Proxy Statement for the Annual Meeting of the Shareholders to be held April 28, 2006, to be filed with the SEC within 120 days of the end of the Company’s year ended December 31, 2005.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

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


		PAGE

Report of Independent Registered Public Accounting Firm		42
Consolidated Statement of Operations for the years ended December 31, 2005, 2004 and 2003		44
Consolidated Balance Sheet as of December 31, 2005 and 2004		45
Consolidated Statement of Cash Flows for the years ended December 31, 2005, 2004 and 2003		47
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		49
Notes to the Consolidated Financial Statements		50

(2) Financial Statement Schedule:


Schedule II — Valuation and qualifying accounts		93

(3) Exhibits:


EXHIBIT
NUMBER				DESCRIPTION

	3	(a)	—	Corrected Restated Certificate of Incorporation of the Company, as amended on September 21, 1998 (incorporated by reference to Exhibit 3(c) to the Company’s Annual Report on Form 10-K for the fiscal year ended August 31, 1998).
	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 May 2, 2002, between the Company and JPMorgan Chase Bank, as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 to the Company’s S-4 Registration Statement No. 333-91708).
	4	(d)	—	First Supplemental Indenture dated as of May 2, 2002, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q dated May 7, 2003).
	4	(e)	—	Second Supplemental Indenture dated as of February 1, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4(d) to the Company’s Form 10-K dated March 10, 2004).
	4	(f)	—	Third Supplemental Indenture dated as of October 7, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 of the Company’s 10-Q dated November 13, 2003).
	4	(g)	—	Fourth Supplemental Indenture dated as of October 10, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.2 of the Company’s 10-Q dated November 13, 2003).
	4	(h)	—	Indenture dated as of October 10, 2003 between the Company, as issuer, certain Subsidiary Guarantors (as defined therein) and JPMorgan Chase Bank, as Trustee, respecting the 9.625% Senior Notes due 2013 (incorporated by reference to the Company’s S-4 Registration Statement No. 333-110374 dated November 10, 2003).
	4	(i)	—	Credit Agreement among Parker Drilling Company, as Borrower, the Several Lenders Parties thereto, Lehman Brothers, Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America, N.A., as Syndication Agent and Lehman Commercial Paper, Inc. as Administrative Agent dated December 20, 2004 (incorporated by reference to Exhibit 99.1 to Form 8-K dated December 27, 2004).

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)

EXHIBIT

NUMBER

DESCRIPTION

4 (j) — 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 (k) — 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).

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(c) 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 April 27, 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 April 27, 2005).*

10 (n) — Consulting Agreement entered into between the Company and James W. Whalen, effective October 29, 2005 (incorporated by reference to Exhibit 10.1 to Form 8-K dated November 1, 2005).*

10 (o) — 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 (p) — 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).*

21 — Subsidiaries of the Registrant.

23 — Consent of Independent Registered Public Accounting Firm.

31 .1 — Robert L. Parker Jr., President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.

31 .2 — W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.

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


Column A	Column B		Column C				Column D		Column E
	Balance at		Charged to		Charged to				Balance at
	beginning		cost and		other				end of
Classifications	of year		expenses		accounts (1)		Deductions (2)		year

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	$	71,497	$	—
Year ended December 31, 2004:
Allowance for doubtful accounts and notes	$	4,732	$	620	$	—	$	1,761	$	3,591
Reduction in carrying value of rig materials and supplies	$	4,681	$	2,400	$	—	$	613	$	6,468
Deferred tax valuation allowance	$	18,867	$	37,136	$	—	$	—	$	56,003
Year ended December 31, 2003:
Allowance for doubtful accounts and notes	$	4,763	$	420	$	—	$	451	$	4,732
Reduction in carrying value of rig materials and supplies	$	3,443	$	2,400	$	—	$	1,162	$	4,681
Deferred tax valuation allowance	$	7,009	$	11,858	$	—	$	—	$	18,867


(1)		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.

(2)		In 2005, 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.

SIGNATURES

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

PARKER DRILLING COMPANY

By: /s/ Robert L. Parker Jr.

Robert L. Parker Jr.

President and Chief Executive Officer and Director

Date: March 8, 2006

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 Robert L. Parker	Chairman of the Board and Director	March 8, 2006

By:	/s/ James W. Whalen James W. Whalen	Vice Chairman of the Board and Director	March 8, 2006

By:	/s/ Robert L. Parker Jr. Robert L. Parker Jr.	President and Chief Executive Officer and Director (Principal Executive Officer)	March 8, 2006

By:	/s/ David C. Mannon David C. Mannon	Senior Vice President and Chief Operating Officer	March 8, 2006

By:	/s/ W. Kirk Brassfield W. Kirk Brassfield	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	March 8, 2006

By:	/s/ Lynn G. Cullom Lynn G. Cullom	Controller (Principal Accounting Officer)	March 8, 2006

By:	/s/ George J. Donnelly George J. Donnelly	Director	March 8, 2006

By:	/s/ Dr. Robert M. Gates Dr. Robert M. Gates	Director	March 8, 2006

By:	/s/ John W. Gibson John W. Gibson	Director	March 8, 2006

By:	/s/ Robert W. Goldman Robert W. Goldman	Director	March 8, 2006

By:	/s/ Robert E. McKee III Robert E. McKee III	Director	March 8, 2006


		PAGE

PART I
Item 1.	Business		1
Item 1A.	Risk Factors		7
Item 1B.	Unresolved Staff Comments		17
Item 2.	Properties		17
Item 3.	Legal Proceedings		19
Item 4.	Submission of Matters to a Vote of Security Holders		19
Item 4A.	Executive Officers		19

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		21
Item 6.	Selected Financial Data		22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		41
Item 8.	Financial Statements and Supplementary Data		42
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		87
Item 9A.	Controls and Procedures		87
Item 9B.	Other Information		88

PART III
Item 10.	Directors and Executive Officers of the Registrant		89
Item 11.	Executive Compensation		89
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		89
Item 13.	Certain Relationships and Related Transactions		89
Item 14.	Principal Accounting Fees and Services		89

PART IV
Item 15.	Exhibits and Financial Statement Schedule		90
Signatures			94
First Amendment to Credit Agreement dated December 1, 2004
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm
Robert L. Parker Jr., President and CEO, Rule 13a-14a/15d-14a Certification
W. Kirk Brassfield, SVP and CFO, Rule 13a-14a/15d-14a Certification
Robert L. Parker Jr., President and CEO, Section 1350 Certification
W. Kirk Brassfield, SVP and CFO, Section 1350 Certification


	(2)	Robert L. Parker Jr., 57, president 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. He has been a director since 1973.

	(3)	David C. Mannon, 48, senior vice president and chief operating officer, joined Parker Drilling in December 2004. 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.

	(4)	W. Kirk Brassfield, 50, 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.

	(5)	Denis J. Graham, 56, 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.

	(6)	Ronald C. Potter, 52, 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.

	(7)	Lynn G. Cullom, 51, 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, including vice president of financial reporting and planning for Coastal Mart, a subsidiary of Coastal Corporation from September 1979 through February 2001.

	(8)	Michael D. Drennon, 50, 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.


Note 9 —	Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS)